Use these links to rapidly review the document
TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
TABLE OF CONTENTS 3

As filed with the Securities and Exchange Commission on August 21, 2012

Registration No. 333-                        

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Summit Midstream Partners, LP
(Exact Name of Registrant as Specified in its Charter)

2100 McKinney Avenue
Suite 1250
Dallas, Texas 75201
(214) 242-1955
(Address, including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

Brock M. Degeyter
Senior Vice President and General Counsel
2100 McKinney Avenue
Suite 1250
Dallas, TX 75201
(214) 242-1955
(Name, Address, including Zip Code, and Telephone Number, including
Area Code, of Agent for Service)

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

          If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

          If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

          If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

          If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

CALCULATION OF REGISTRATION FEE

(1)

Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   

---

Table of Contents

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated August 21, 2012

PROSPECTUS

---

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

---

This is the initial public offering of our common units representing limited partner interests. We are offering             common units in this offering. We currently expect that the initial public offering price will be between $             and $             per common unit. Prior to this offering, there has been no public market for our common units.

We have applied to list our common units on the New York Stock Exchange under the symbol "SMLP."

We are an "emerging growth company" as defined in Section 101 of the Jumpstart Our Business Startups Act, or JOBS Act.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 20.

These risks include the following:

•

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.



•

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 or for the twelve months ended June 30, 2012.



•

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.



•

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.



•

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to our unitholders over the long-term.



•

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.



•

Summit Midstream Partners, LLC, which we refer to as "Summit Investments," owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and has limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other unitholders.



•

Our partnership agreement restricts the rights of holders of our common units with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.



•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.



•

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.



•

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.



•

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

We have granted the underwriters the option to purchase up to an additional             common units on the same terms and conditions set forth above if the underwriters sell more than              common units in this offering.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about                    , 2012, through the book-entry facilities of The Depository Trust Company.

---

---

Prospectus dated                    , 2012

---

Table of Contents

---

Table of Contents

TABLE OF CONTENTS

i

---

Table of Contents

ii

---

Table of Contents

        You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making

iii

---

Table of Contents

an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

Industry and Market Data

        The data included in this prospectus regarding the midstream natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management's knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management's knowledge and experience we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.

iv

---

Table of Contents

 

1

---

Table of Contents

2

---

Table of Contents

3

---

Table of Contents

4

---

Table of Contents

5

---

Table of Contents

6

---

Table of Contents

7

---

Table of Contents

8

---

Table of Contents

9

---

Table of Contents

10

---

Table of Contents

11

---

Table of Contents

12

---

Table of Contents

 

13

---

Table of Contents

14

---

Table of Contents

15

---

Table of Contents

16

---

Table of Contents

17

---

Table of Contents

18

---

Table of Contents

19

---

Table of Contents

RISK FACTORS

        Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were to materialize, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.

        In order to pay the minimum quarterly distribution of $            per unit per quarter, or $            per unit on an annualized basis, we will require available cash of approximately $             million per quarter, or $             million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the volume of natural gas we gather and compress;



•

the level of production of natural gas from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, natural gas and natural gas liquids, or NGLs;



•

damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism;



•

leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise;



•

changes in the fees we charge for our services;



•

the level of competition from other midstream energy companies in our geographic markets;



•

changes in the level of our operating, maintenance and general and administrative costs;



•

regulatory action affecting the supply of, or demand for, natural gas, the fees we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and



•

prevailing economic and market conditions.

        In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

•

the level and timing of capital expenditures we make;

20

---

Table of Contents

•

the level of our operating and general and administrative expenses, including reimbursements to our general partner for services provided to us;



•

the cost of acquisitions, if any;



•

our debt service requirements and other liabilities;



•

fluctuations in our working capital needs;



•

our ability to borrow funds and access capital markets;



•

restrictions contained in our debt agreements;



•

the amount of cash reserves established by our general partner; and



•

other business risks affecting our cash levels.

        For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 or for the twelve months ended June 30, 2012.

        We must generate approximately $             million of available cash to pay the minimum quarterly distribution for four quarters on all of our common and subordinated units that will be outstanding immediately following this offering, as well as the corresponding distribution on our 2.0% general partner interest. The amount of cash available for distribution that we generated during the year ended December 31, 2011 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of our subordinated units for that period. In addition, the amount of cash available for distribution that we generated during the twelve months ended June 30, 2012 would have been sufficient to pay a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all common units, and would have been insufficient to make any distribution on our subordinated units for that period. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Our Cash Distribution Policy and Restrictions on Distributions."

The assumptions underlying the forecast of cash available for distribution that we include in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2013. We estimate that our total cash available for distribution for the twelve months ending September 30, 2013 will be approximately $95.9 million, as compared to approximately $39.9 million for the year ended December 31, 2011 and approximately $39.9 million for the twelve months ended June 30, 2012 on a historical as adjusted basis. To the extent that volumes on either the Grand River system or the DFW Midstream system are lower than we project, our revenues during the forecast period will be adversely affected. If the actual volume of natural gas we gather on our systems for the twelve months ending September 30, 2013 is 10% lower than our forecast, we expect we would have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to holders of our common units but only        % of the aggregate annualized minimum quarterly distribution to the holders of our

21

---

Table of Contents

subordinated units. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.

        A significant percentage of our revenue is attributable to a relatively small number of customers. Chesapeake, Carrizo Oil & Gas, Inc., or Carrizo, Energy Transfer Fuels and TOTAL accounted for approximately 34%, 17%, 12% and 10%, respectively, of our revenue for the year ended December 31, 2011. Encana, Carrizo and Chesapeake accounted for approximately 29%, 16% and 16%, respectively, of our revenue for the six months ended June 30, 2012. If our customers curtail or reduce production in our areas of operation it could reduce throughput on our system and, therefore, adversely affect our revenues, cash flow and ability to make distributions to our unitholders. For example, in January 2012 Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region as well as reduce its dry gas production by up to 500 MMcf/d. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011 primarily as a result of Chesapeake's publicly announced reduction in production. Please read "—Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve."

        Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenue and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue. In addition, if any one or more of our gas gathering agreements that account for 25% or more of our revenues are terminated, and such termination is reasonably expected to have a Material Adverse Effect (as defined in our amended and restated revolving credit facility), and a replacement agreement is not obtained within 30 days, this would constitute an event of default under our amended and restated revolving credit facility and our lenders would be able to accelerate payment of the debt outstanding thereunder.

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

        Our operations are focused on natural gas gathering and compression services. Our assets are located exclusively in the Piceance Basin in western Colorado and the Barnett Shale region in north-central Texas and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our financial condition, results of operations and cash flows depend

22

---

Table of Contents

upon the demand for our services in these regions. Due to our lack of industrial and geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. For example, a significant portion of the gas we gather in the Piceance Basin and the Barnett Shale is dry gas. Due to recent declines in natural gas prices, several of our customers have substantially reduced their dry gas production in these regions and announced their intent to reduce capital expenditures for dry gas drilling activities.

        A significant portion of our operations are concentrated in the Barnett Shale region, which could disproportionately expose us to operational and regulatory risk in that area. The location of the Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for natural gas in urban and suburban communities. The DFW Midstream system is within the city limits of various municipalities in that region, including Arlington, Texas. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs, which has led producers to pursue a high-density pad site drilling strategy. Furthermore, the process of obtaining permits for constructing additional gathering lines to deliver our customers' natural gas to market may be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to you over the long-term.

        Lower natural gas prices over the long-term could result in a decline in the production of natural gas resulting in reduced throughput on our systems. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $3.21 per MMBtu as of July 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration, the EIA, average annual natural gas production in the United States increased 13.9% from 55.2 Bcf/d to 62.9 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.8 Tcf as of August 5, 2011 to approximately 3.2 Tcf as of August 3, 2012, due to the unseasonably warm winter of 2011/2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 430 as of July 31, 2012 according to Smith Bits (a unit of Schlumberger Limited), as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

        The decline in natural gas prices has had a negative impact on exploration, development and production activity in our areas of operation. If natural gas prices remain depressed or decrease further, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        Also, higher natural gas prices over the long-term could result in a decline in the demand for natural gas and, therefore, in the throughput on our systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

23

---

Table of Contents

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.

        The natural gas volumes that support our business depend on the level of production from natural gas wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.

        We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

•

the availability and cost of capital;



•

prevailing and projected commodity prices, including the prices of oil, natural gas and NGLs;



•

demand for oil, natural gas and NGLs;



•

levels of reserves;



•

geological considerations;



•

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and



•

the availability of drilling rigs and other costs of production and equipment.

        Fluctuations in energy prices can also greatly affect the development of new oil and natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas, or LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Recent declines in natural gas prices have had a negative impact on exploration, development and production activity and, if sustained, could lead to further decreases in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with

24

---

Table of Contents

these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.

        Many of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experience a reduction in throughput, which would result in a decline in our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

        Because of these and other factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

If our customers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.

        If we are not successful in attracting new customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from our existing customers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements, our customers are not obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in January 2012, Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region and to reduce its total dry gas production by up to 500 MMcf/d. Similarly, in February 2012, Encana announced its intent to reduce its dry gas production to approximately 3.1 Bcf/d, a decrease of approximately 250 MMcf/d from 2011 levels. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011, primarily as a result of Chesapeake's publicly announced reduction in production. Encana's public announcement has not impacted the volume on our Grand River system but may do so in the future. Any further reductions by Chesapeake or our other customers in our areas of operation could result in further reductions in throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

        Our gas gathering agreements were designed to generate stable cash flows to us over the life of the MVC contract term while also minimizing direct commodity price risk. The primary mechanism on which we rely to generate our stable cash flows is a minimum volume commitment, or MVC, from our customers. Under these MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, the majority of our gas gathering agreements also include an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering system (or an equivalent monetary amount) over the MVC term. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, many of our GGAs contain provisions that allow the customer to use the excess volumes or the shortfall

25

---

Table of Contents

payment to credit against future excess volumes or future shortfall payments in subsequent periods. These provisions include the following:

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable). As of June 30, 2012, we recorded an aggregate of $7.6 million of deferred revenue with respect to shortfall payments that could reduce gathering fees received in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.



•

To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped volumes in excess of its MVCs. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.



•

To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in future periods, subject to expiration in the event that there is no shortfall in subsequent periods. In such a situation, we would receive lower gathering fees in a particular contract year than we would otherwise be entitled to receive under the customer's MVC.

        Under certain circumstances, some or all of these provisions can apply in combination with one another. It is possible that the combined effect of these mechanisms could result in our receiving no revenues or cash flows from one or more customers in a given period. In the most extreme circumstances we could:

•

incur operating expenses with no corresponding revenues from one or more significant customers for a period of up to 35 months; or



•

all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregate MVCs have been satisfied with previous throughput volume shipments.

If either of these circumstances were to occur, it would have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make distributions to our unitholders.

We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

        We do not have and we do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of natural gas reserves connected to our systems, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires subjective estimates of underground

26

---

Table of Contents

accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs.

        Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

        We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our AMIs, non-customer producers that lease acreage within one of our AMIs and produce natural gas may choose to use one of our competitors to gather that natural gas.

        In addition, our customers may develop their own gathering systems outside of our AMIs. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

        We gather the natural gas on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain AMIs from new customers in the future, and we may be unable to renew existing AMIs with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

•

the level of existing and new competition to provide gathering services to our markets;



•

the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;



•

the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;



•

the extent to which the customers in our markets are willing to contract on a long-term basis; and



•

the effects of federal, state or local regulations on the contracting practices of our customers.

        To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

27

---

Table of Contents

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operating results.

        Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our counterparties will perform or adhere to existing or future contractual arrangements.

        The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.

        Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.

        Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenue and cash flow and our ability to make distributions to our unitholders could be adversely affected.

        Our natural gas gathering pipelines connect to other pipelines and midstream facilities, such as processing plants, owned and operated by unaffiliated third parties, such as Energy Transfer Partners, L.P., Enterprise Products Partners L.P. and others. For example, all of the volumes we currently gather on the Grand River system are delivered to Enterprise Products Partners L.P.'s processing plant in Meeker, Colorado. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other operational hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities, including the Meeker processing plant, and the agreements we do have may be terminated in certain circumstances and on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas that we gather, our revenue, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

We have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and operating results.

        We purchased the substantial majority of our initial assets from Energy Future Holdings and Chesapeake in September 2009 and from Encana in October 2011. As a result, our executive management team has a limited history of operating our assets. There may be historical occurrences or

28

---

Table of Contents

latent issues regarding our pipeline systems that our executive management team may be unaware of and that may have a material adverse effect on our business and results of operations. The steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time to connect additional wells and maintain throughput volume. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

A shortage of skilled labor in the midstream natural gas industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.

        The gathering of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner's employees, our results of operations could be materially and adversely affected.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

        Our operations are subject to all of the risks and hazards inherent in the gathering, compressing and dehydrating of natural gas, including:

•

damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;



•

inadvertent damage from construction, vehicles, farm and utility equipment;



•

leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;



•

ruptures, fires and explosions; and



•

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

        These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. These risks may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive minimum volume commitments to customers during times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers,

29

---

Table of Contents

with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.

        Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover for potential environmental liabilities.

None of the proceeds of this offering will be used to maintain or grow our asset base.

        None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to pay future distributions at the then-current level. The net proceeds of the offering will be used to repay amounts outstanding under our amended and restated revolving credit facility and to make a cash distribution to Summit Investments to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us.

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

        Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

        If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, (iii) outbid by competitors, or (iv) we are unable to obtain necessary governmental or third-party consents or for any other reason, then our future growth and ability to increase cash distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

30

---

Table of Contents

        Any acquisition involves potential risks, including, among other things:

•

mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;



•

an inability to secure adequate customer commitments to use the acquired systems or facilities;



•

the risk that natural gas or crude oil reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;



•

an inability to integrate successfully the assets or businesses we acquire;



•

coordinating geographically disparate organizations, systems and facilities;



•

the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;



•

mistaken assumptions about the overall costs of equity or debt;



•

the diversion of management's and employees' attention from other business concerns;



•

unforeseen difficulties operating in new geographic areas and business lines; and



•

customer or key employee losses at the acquired businesses.

        If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

        One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

        For instance, as we develop our medium pressure system to serve the Mancos and Niobrara Shale formations, the construction will occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

        In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way or federal and state environmental or other authorizations. The approval process for gathering activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas. Such

31

---

Table of Contents

authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such rights-of-way or other authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be adversely affected.

We require access to significant amounts of additional capital to implement our growth strategy, as well as to meet potential future capital requirements under certain of our gas gathering agreements. Tightened capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

        In order to expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We expect to make substantial expansion capital expenditures during the twelve months ending September 30, 2013. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gas gathering agreements also require us to spend significant amounts of capital, including over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. For example, in connection with our acquisition of the Grand River system, we agreed to invest capital, subject to a maximum of $200 million in any annual period, to construct the necessary facilities to support Encana's drilling program in the Mancos and Niobrara shale formations. Depending on our customers' future development plans, it is possible that the capital we would be required to spend to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our amended and restated credit facility.

        We will be required to use cash from operations or incur borrowings or sell additional common units or other securities in order to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. If we are unable to raise expansion capital, we may lose the opportunity to make acquisitions or to gather natural gas production from new upstream projects developed by our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

        We do not have any commitment from our sponsors or their affiliates, including Energy Capital Partners and GE Energy Financial Services, to provide any direct or indirect financial assistance to us following the closing of this offering.

32

---

Table of Contents

Because our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

        Interest rates are generally at or near historic lows and may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

        Upon the closing of this offering, we expect to have approximately $     million of total indebtedness and $     million available for future borrowings under our amended and restated revolving credit facility. Our future level of debt could have important consequences to us, including the following:

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;



•

our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;



•

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and



•

our flexibility in responding to changing business and economic conditions may be limited.

        Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our amended and restated revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

        Our amended and restated revolving credit facility limits our ability to, among other things:

•

incur or guarantee additional debt;



•

make distributions on or redeem or repurchase units;



•

make certain investments and acquisitions;



•

make capital expenditures;



•

incur certain liens or permit them to exist;

33

---

Table of Contents

•

enter into certain types of transactions with affiliates;



•

merge or consolidate with another company or otherwise engage in a change of control; and



•

transfer, sell or otherwise dispose of assets.

        Our amended and restated revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. In addition, our credit facility contains events of default customary for credit facilities of this size and nature. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for additional information.

        The provisions of our amended and restated revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our amended and restated revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

A portion of our revenues are exposed to changes in oil and natural gas prices, and our exposure may increase in the future.

        For the year ended December 31, 2011 and the six months ended June 30, 2012, we generated approximately 80% and 84%, respectively, of our revenues pursuant to long-term, fee-based gas gathering agreements under which we are paid based on the volumes of natural gas that we gather rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. For example, in the future we may enter into percent-of-proceeds contracts with our customers, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of natural gas and NGLs.

        Substantially all of our remaining revenue is derived from (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with our electric-drive compression and (ii) the sale of condensate volumes that we collect on the Grand River system. Our revenues with respect to our sale of retained natural gas are tied to the price of natural gas. In addition, changes in the price of oil could directly affect the revenues we receive fom the sale of condensate.

        Furthermore, we may acquire or develop additional midstream assets in the future, including assets related to commodities other than natural gas, that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.

A change in laws and regulations applicable to our assets or services may cause our operating and maintenance expenses to increase or revenue to decline.

        Various aspects of our operations are subject to extensive and frequently changing regulation as the activities of the natural gas industry often are reviewed by legislators and regulators. More stringent legislation or regulation or taxation of natural gas drilling activity could directly curtail such activity or

34

---

Table of Contents

increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. Numerous federal, state and local departments and agencies are authorized by statute to issue, and have issued, rules and regulations binding upon participants in the natural gas industry. Our operations and the markets in which we participate are affected by these laws and regulations and may be affected by changes to such laws and regulations, which may cause us to incur materially increased operating costs or realize materially lower revenues or both.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

        A portion of our customers' natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers. In addition, the federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected to be available between late 2012 and 2014. On May 4, 2012, the Department of the Interior's Bureau of Land Management ("BLM") issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans. Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. The chemical ingredient information for hydraulic fracturing fluid is generally available to the public through online databases, and this may bring more public scrutiny to hydraulic fracturing operations. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations.

We are subject to federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements, and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

        We believe that our pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of the Federal Energy Regulatory Commission, also known as FERC, under the Natural Gas Act of 1938, also known as the NGA, and the Natural Gas Policy Act of 1978, also known as the NGPA. We are, however, subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, also known as EPAct 2005, and to FERC's regulations thereunder, which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, the Federal Trade Commission, also known as FTC, holds statutory authority under the Energy Independence and Security Act of 2007, also known as the EISA, to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. FTC is also authorized to seek fines of up to one million dollars ($1,000,000) per day per violation. The Commodity Futures Trading Commission, also known as

35

---

Table of Contents

the CFTC, is directed under the Commodity Exchange Act, also known as the CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, also known as the Dodd-Frank Act, and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for each violation of the anti-market manipulation sections of the CEA.

        The distinction between federally-unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

        State and municipal regulations also affect our business. We are subject to state and local regulation regarding the construction and operation of our gathering systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of gas we may gather. Ratable take statutes and regulations generally require gatherers to take natural gas production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather. Many states have adopted complaint-based regulation of gathering activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering, including state regulation of production rates, maximum daily production allowable from gas wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs, and revenues.

We are subject to stringent laws and regulations that may expose us to significant costs and liabilities.

        Our natural gas gathering, compression and dehydrating operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Examples of these laws include:

•

the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;



•

the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;



•

the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;



•

the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;

36

---

Table of Contents

•

the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;



•

the Endangered Species Act, also known as the ESA; and



•

the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

        These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

        There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read "Business—Environmental Matters" for more information.

We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.

        The U.S. Department of Transportation, also known as DOT, through its Pipeline and Hazardous Materials Safety Administration, also known as PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in "high consequence areas," which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is

37

---

Table of Contents

located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

Our pipelines have become subject to increased penalties and may become subject to more stringent safety regulation.

        Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and extend the integrity management requirements to certain gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

        In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that our sources, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. Depending on the particular program, we may be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

38

---

Table of Contents

        Independent of Congress, the EPA has begun to adopt federal-level regulations controlling GHG emissions under its existing Clean Air Act authority. In 2009, the EPA issued required findings under the Clean Air Act concluding that emissions of GHGs present an endangerment to human health and the environment, and issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in September 2012. We are required to report our GHG emissions for certain of our assets. On May 12, 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

        Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

        In July 2010 Congress enacted the Dodd-Frank Act. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through regulation, primarily through rules to be adopted by the CFTC. The Dodd-Frank Act provisions are intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that may impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements.

        We currently receive a fuel retainage fee from certain of our customers that is paid in-kind to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to hedge our exposure to fluctuations in the price of natural gas with respect to those volumes. The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market

39

---

Table of Contents

as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

        Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

        We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiated rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

        Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

        Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our

40

---

Table of Contents

obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley, which we refer to as Section 404.

        Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

        Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the fiscal year ending December 31, 2013. In addition, pursuant to the recently enacted JOBS Act, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until the later of the year following our first annual report required to be filed with the SEC or the date we are no longer an "emerging growth company," which may be up to five full fiscal years following this offering.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

        The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Risks Inherent in an Investment in Us

Summit Investments owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other common unitholders.

        Following this offering, Summit Investments will control our general partner, and appoint all of the officers and directors of our general partner, some of whom will also be officers, directors or principals of Energy Capital Partners or GE Energy Financial Services, the entities that own and control Summit Investments. Although our general partner has a duty to manage us in a manner that is in our best interests, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, Summit Investments. Conflicts of interest will arise between Summit Investments, its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Summit Investments and its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

•

Neither our partnership agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift the focus of its investment and growth to areas not served by our assets.

41

---

Table of Contents

•

Summit Investments is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.



•

Our general partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest.



•

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our general partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.



•

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.



•

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.



•

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.



•

Our general partner determines which costs incurred by it are reimbursable by us.



•

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.



•

Our partnership agreement permits us to classify up to $             million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.



•

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.



•

Our general partner intends to limit its liability regarding our contractual and other obligations.



•

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.



•

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.



•

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.



•

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general

42

---

Table of Contents

partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Please read "Conflicts of Interest and Duties."

Our sponsors are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

        Energy Capital Partners and GE Energy Financial Services have significantly greater resources than us and have experience making investments in midstream energy businesses. Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own interests in entities that compete with us. Energy Capital Partners and GE Energy Financial Services are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, GE Energy Financial Services owns an interest in another publicly traded midstream master limited partnership. In addition, in the future, Energy Capital Partners or GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Energy Capital Partners or GE Energy Financial Services may offer us the opportunity to buy additional assets, neither of them are under any contractual obligation to do so and we are unable to predict whether or when such opportunities may arise.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its officers and directors or any of its affiliates, including our sponsors and their respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Duties."

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

        Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters' option to purchase additional common units. In addition, affiliates of our general partner will own            common and             subordinated units, representing an aggregate        % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

        The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may

43

---

Table of Contents

decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•

our quarterly distributions;



•

our quarterly or annual earnings or those of other companies in our industry;



•

the loss of a large customer;



•

announcements by us or our competitors of significant contracts or acquisitions;



•

changes in accounting standards, policies, guidance, interpretations or principles;



•

general economic conditions;



•

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;



•

future sales of our common units; and



•

other factors described in these "Risk Factors."

Our partnership agreement replaces our general partner's fiduciary duties to holders of our common and subordinated units with contractual standards governing its duties.

        Our partnership agreement contains provisions that eliminate fiduciary duties to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duties to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•

how to allocate corporate opportunities among us and its affiliates;



•

whether to exercise its limited call right;



•

whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;



•

how to exercise its voting rights with respect to the units it owns;



•

whether to exercise its registration rights;



•

whether to elect to reset target distribution levels;



•

whether to transfer the incentive distribution rights or any units it owns to a third party; and



•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

        By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of our General Partner."

44

---

Table of Contents

Our partnership agreement limits the liabilities of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that limit the liability of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;



•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;



•

our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and



•

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:



•

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;



•

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties."

45

---

Table of Contents

        Our partnership agreement provides that our conflicts committee may be comprised of one or more independent directors. If we establish a conflicts committee with only one independent director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

        In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

        While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our general partner) after the subordination period has ended. At the closing of this offering, affiliates of our general partner will own, directly or indirectly, approximately         % of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of Our Partnership Agreement."

46

---

Table of Contents

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

        Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Summit Investments, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, which we project to be approximately $19.6 million for the twelve months ending September 30, 2013. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner's board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        In the event of a reset of target distribution levels, our general partner will be entitled to receive the number of common units equal to that number of common units that would have entitled it to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership

47

---

Table of Contents

Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Summit Investments. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

        The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, affiliates of our general partner will own        % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

48

---

Table of Contents

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Summit Investments to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote or consent of the unitholders.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer the incentive distribution rights it owns to a third party at any time without the consent of our unitholders. If our general partner transfers the incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our business and increase quarterly distributions to unitholders over time as it would if it had retained ownership of the incentive distribution rights. For example, a transfer of the incentive distribution rights by our general partner could reduce the likelihood of Summit Investments selling or contributing additional midstream assets to us, as Summit Investments would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

You will experience immediate and substantial dilution in net tangible book value of $            per common unit.

        The estimated initial public offering price of $            per common unit exceeds our net tangible book value of $             per unit. Based on the estimated initial public offering price of $            per common unit, you will incur immediate and substantial dilution of $            per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."

We may issue additional units without your approval, which would dilute your existing ownership interests.

        Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our existing unitholders' proportionate ownership interest in us will decrease;



•

the amount of cash available for distribution on each unit may decrease;



•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;



•

because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;



•

the ratio of taxable income to distributions may increase;

49

---

Table of Contents

•

the relative voting strength of each previously outstanding unit may be diminished; and



•

the market price of the common units may decline.

Summit Investments may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

        After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, Summit Investments will hold an aggregate of                        common units and                        subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, we have agreed to provide Summit Investments with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, Summit Investments will own approximately        % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Summit Investments will own approximately        % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

•

we were conducting business in a state but had not complied with that particular state's partnership statute; or



•

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

        For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

50

---

Table of Contents

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

        Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

        We have applied to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management."

We will incur increased costs as a result of being a publicly traded partnership.

        We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

        We have included $2.5 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

51

---

Table of Contents

Tax Risks

        In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

        Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

        Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation

52

---

Table of Contents

at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read "Material Federal Income Tax Consequences—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

        Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

        If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."

53

---

Table of Contents

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

        Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election."

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations and, although the U.S. Treasury Department issued proposed regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or

54

---

Table of Contents

deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and would result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to

55

---

Table of Contents

unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination."

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Texas and Colorado. Colorado currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

56

---

Table of Contents

USE OF PROCEEDS

        We expect to receive net proceeds of approximately $             million, after deducting underwriting discounts, commissions and a structuring fee, but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. Our estimates assume an initial public offering price of $            per common unit. We will use the net proceeds from this offering to:

•

repay $             million outstanding under our amended and restated revolving credit facility;



•

make a cash distribution to Summit Investments of $             million in order to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us; and



•

pay estimated offering expenses of $             million.

        As of August 20, 2012, we had $347.2 million of indebtedness outstanding under our revolving credit facility, with a weighted average interest rate of 2.76%. The amended and restated revolving credit facility matures on May 26, 2016, and borrowings bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. Borrowings made under our amended and restated revolving credit facility within the last twelve months were used primarily to make distributions to our sponsors and fund capital expenditures.

        If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments the number of common units issued upon such exercise.

        The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Affiliates of certain of the underwriters are lenders under our amended and restated revolving credit facility and will, in that respect, receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our amended and restated revolving credit facility. Please read "Underwriting."

        An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, commissions and a structuring fee, to increase or decrease, respectively, by $             million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $            per common unit, would increase net proceeds to us from this offering by approximately $             million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $            per common unit, would decrease the net proceeds to us from this offering by approximately $             million. To the extent there is an increase or decrease in the net proceeds we receive from this offering, we will make a corresponding increase or decrease in the cash distribution to Summit Investments.

57

---

Table of Contents

CAPITALIZATION

        The following table shows:

•

Summit Midstream Predecessor's historical cash and cash equivalents and capitalization, as of June 30, 2012; and



•

our as adjusted cash and cash equivalents and capitalization, as of June 30, 2012, giving effect to:



•

our receipt and use of net proceeds of $             million from the issuance and sale of                         common units to the public at an assumed initial offering price of $            per unit in the manner described in "Use of Proceeds"; and



•

the other transactions described in "Summary—Formation Transactions and Partnership Structure."

        We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations." This table assumes that the underwriters' option to purchase additional common units is not exercised.

58

---

Table of Contents

DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2012, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters' option to purchase additional common units is not exercised, our net tangible book value was $             million, or $            per unit. Net tangible book value excludes $             million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

        The following table sets forth the number of units that we will issue and the total consideration to be contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:

59

---

Table of Contents

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading "—Assumptions and Considerations" below. In addition, please read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical financial statements, and the notes thereto, included elsewhere in this prospectus.

General

        Our Cash Distribution Policy.     Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement. To that end, our partnership agreement requires us to distribute all of our available cash quarterly. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

        Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.     There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to the extent we have available cash as defined in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

•

Our cash distribution policy will be subject to restrictions on distributions under our amended and restated revolving credit facility or other debt agreements entered into in the future. Our amended and restated revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility."



•

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.



•

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Summit Investments) after the subordination period has ended. At the closing of this offering, Summit Investments will own our general partner as well as approximately        % of our outstanding common units and all of our subordinated units, representing an aggregate         % limited partner interest in us.

60

---

Table of Contents

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.



•

Under Section 17-607 of the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.



•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash."



•

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate in order to service or repay our debt or fund expansion capital expenditures.

        All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $             million cash basket, that represent non-operating sources of cash. Consequently, it is possible that distributions from operating surplus may represent a return of capital. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.

        Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital.     Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions, expansion capital expenditures or otherwise, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no restrictions in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional bank borrowings (under our amended and restated revolving credit facility or otherwise) or other debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

        Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $            per unit per complete quarter, or $            per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter

61

---

Table of Contents

ending                     , 2012. This equates to an aggregate cash distribution of approximately $             million per quarter, or approximately $             million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding immediately after the completion of this offering. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to this policy will be subject to the factors described above under the caption "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

        If and to the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds before expenses but after deducting underwriting discounts, commissions and structuring fees. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

        The table below sets forth the number of common and subordinated units to be outstanding upon the closing of this offering and the number of unit equivalents represented by the 2.0% general partner interest and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $            per unit per quarter ($            per unit on an annualized basis).

        The subordination period generally will end if we have earned and paid at least $            on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after                        , 2015. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $            (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest and the related distribution on the incentive distribution rights for any four consecutive quarter period

62

---

Table of Contents

ending on or after                        , 2013. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through                        , 2012 based on the actual length of the period.

        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $            per unit for the twelve months ending September 30, 2013. In those sections, we present two tables, consisting of:

•

"Partnership Unaudited Historical As Adjusted Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution on a historical as adjusted basis for the year ended December 31, 2011 and the twelve months ended June 30, 2012, derived from our historical consolidated financial statements that are included in this prospectus, as adjusted to give effect to the incremental general and administrative expenses associated with being a publicly traded partnership and our estimate of the amount of our historical maintenance capital expenditures; and



•

"Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013," in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve months ending September 30, 2013.

Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the twelve months ended June 30, 2012

        We acquired the Grand River system from Encana in October 2011 and, therefore, our historical consolidated financial statements that are included in this prospectus do not reflect a full year of financial results of the Grand River system. If we had completed our initial public offering and the related transactions contemplated by this prospectus on January 1, 2011, our historical as adjusted cash available for distribution for the year ended December 31, 2011, which includes two months of operations attributable to the Grand River system, would have been approximately $39.9 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of the common units but only a cash distribution of $            per unit per quarter ($            per unit on an annualized basis), or approximately        % of the minimum quarterly distribution, on our subordinated units for such period.

63

---

Table of Contents

        If we had completed our initial public offering and the related transactions contemplated by this prospectus on July 1, 2011, our historical as adjusted cash available for distribution for the twelve months ended June 30, 2012, which includes eight months of operations attributable to the Grand River system, would have been approximately $39.9 million. This amount would have been sufficient to pay a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of the common units, and would have been insufficient to make any distribution on our subordinated units for such period. This shortfall in cash available for distribution is due primarily to eight months of assumed interest expense on debt we are assumed to have incurred to purchase the Grand River system.

        Unaudited historical as adjusted cash available for distribution for the year ended December 31, 2011 and the twelve months ended June 30, 2012 includes incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. These expenses are not reflected in the historical consolidated financial statements of our Predecessor. Our estimate of incremental general and administrative expenses is based upon currently available information.

        The adjusted amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed on January 1, 2011 or July 1, 2011. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on January 1, 2011 or July 1, 2011.

        The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2011 and the twelve months ended June 30, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related transactions contemplated by this prospectus had been consummated on January 1, 2011 and July 1, 2011, respectively. Each of the adjustments presented below is explained in the footnotes to such adjustments.

64

---

Table of Contents

Partnership Unaudited Historical As Adjusted Cash Available for Distribution

65

---

Table of Contents

66

---

Table of Contents

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013

        We forecast that our estimated cash available for distribution for the twelve months ending September 30, 2013 will be approximately $95.9 million. This amount would exceed by $             million the amount needed to pay the total annualized minimum quarterly distribution of $            on all of our units for the twelve months ending September 30, 2013.

        We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements in support of our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2013. This forecast is a forward-looking statement and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions on which we base our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2013. However, this information is not fact and should not be relied

67

---

Table of Contents

upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

        The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The reports of our independent registered public accounting firm included in this prospectus relate to our and our Predecessor's historical financial information, and those reports do not extend to the prospective financial information and should not be read to do so.

        When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2013.

        We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements included elsewhere in this prospectus in support of our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders and the corresponding distributions on our general partner's 2.0% interest for the twelve months ending September 30, 2013. Please read below under "—Assumptions and Considerations" for further information as to the assumptions we have made for the financial forecast.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2013, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

68

---

Table of Contents

Estimated Cash Available for Distribution

69

---

Table of Contents

70

---

Table of Contents

Assumptions and Considerations

        Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all unitholders for the twelve months ending September 30, 2013.

General Considerations

        As discussed further below, a significant portion of the increase in cash available for distribution for the twelve months ending September 30, 2013 as compared to the year ended December 31, 2011 and the twelve months ended June 30, 2012 is attributable to additional revenues that we expect to generate under gas gathering agreements related to our Grand River system and to a decrease in interest expense as compared to the assumed interest expense related to assumed borrowings to finance historical capital expenditures. Because we acquired the Grand River system in October 2011, revenues from these gas gathering agreements are not included in our historical results prior to November 2011.

Revenue

        We estimate that we will generate revenue of $163.2 million for the twelve months ending September 30, 2013, compared to $103.6 million for the year ended December 31, 2011 and $137.6 million for the twelve months ended June 30, 2012. The significant increase in revenue for the forecast period as compared to the year ended December 31, 2011 and the twelve months ended June 30, 2012 is primarily attributable to the inclusion of our Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011 and just eight months for the twelve months ended June 30, 2012. Approximately 46% of our projected revenue is expected to be generated from our Grand River system and approximately 54% is expected to be generated from our DFW Midstream system for the twelve month period ending September 30, 2013. Approximately 87% of our revenue is associated with fee-based gathering services that we provide to our customers. Approximately 9% of our revenue is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collect on our Grand River system. We generate the remainder of our revenue by charging certain customers with respect to costs we incur on their behalf to deliver pipeline quality natural gas to third-party pipelines and costs we incur to operate electric-drive compression on the Grand River system.

•

Volumes.  We estimate that we will gather an average of 927 MMcf/d for the twelve months ending September 30, 2013. This compares to our average daily throughput in the first half of 2012 of approximately 909 MMcf/d and an average of 432 MMcf/d for the year ended December 31, 2011 and 733 MMcf/d for the twelve months ended June 30, 2012. This expected increase in volumes in the forecast period as compared to the year ended December 31, 2011 and the twelve months ended June 30, 2012 is primarily due to our acquisition of the Grand River system in October 2011 and is partially offset by natural declines in production from existing wells on both of our gathering systems.



•

Grand River volumes. Our average daily throughput on the Grand River system in the first half of 2012 was approximately 584 MMcf/d. We expect throughput will average approximately 581 MMcf/d for the twelve months ending September 30, 2013, primarily based on (i) production schedules provided by certain of our customers and (ii) our assumption that our other customers will drill and connect new wells to offset the natural

71

---

Table of Contents

decline of existing wells connected to the Grand River system, thereby keeping throughput in the forecast period relatively flat with current throughput. Projected throughput for the twelve months ending September 30, 2013 compares to aggregate minimum volume commitments of 483 MMcf/d from our Grand River customers over the same time period and average daily throughput of 596 MMcf/d for the two months ended December 31, 2011 and 587 MMcf/d for the eight months ended June 30, 2012.

•

DFW Midstream volumes. Our average daily throughput on the DFW Midstream system in the first half of 2012 was approximately 325 MMcf/d. We expect throughput on the DFW Midstream system will average approximately 346 MMcf/d for the twelve months ending September 30, 2013, primarily based on our recent addition of a new customer, Beacon E&P Company, LLC, or Beacon E&P, and our assumption that in the aggregate, our other customers' production will be more than sufficient to offset the natural decline of existing wells connected to the DFW Midstream system. Projected throughput for the twelve months ending September 30, 2013 compares to aggregate minimum volume commitments of 175 MMcf/d from our DFW Midstream customers over the same time period and average throughput of 333 MMcf/d for the year ended December 31, 2011 and 343 MMcf/d for the twelve months ended June 30, 2012.



•

Fees.  We estimate that we will receive an average gathering fee of $0.42 per Mcf for the twelve months ending September 30, 2013, compared to $0.53 per Mcf for the year ended December 31, 2011 and $0.42 per Mcf for the twelve months ended June 30, 2012. Our calculation of the average gathering fee is based on an analysis of the projected volumes and fixed contractual fees (subject to contractual escalation in certain cases) under each of our gas gathering agreements. We expect our overall average gathering fee to be lower in the forecast period as compared to the year ended December 31, 2011 and in line with the twelve months ended June 30, 2012 primarily as a result of the inclusion of our Grand River system, which generates a lower average gathering fee per Mcf than our DFW Midstream system, in the entire forecast period. All of our gathering fees are fixed and subject to the terms of the gas gathering agreements we have with each of our customers.



•

Grand River Fees. Our average gathering fees on the Grand River system for the year ended December 31, 2011 and the twelve months ended June 30, 2012 were $0.30 per Mcf and $0.28 per Mcf, respectively. We estimate that we will receive an average gathering fee on the Grand River system of $0.31 per Mcf for the twelve months ending September 30, 2013.



•

DFW Midstream Fees. Our average gathering fees on the DFW Midstream system for the year ended December 31, 2011 and the twelve months ended June 30, 2012 were $0.60 per Mcf and $0.58 per Mcf, respectively. We estimate that we will receive an average gathering fee on the DFW Midstream system of $0.60 per Mcf for the twelve months ending September 30, 2013.



•

Natural Gas and Condensate Sales.  Approximately 9% of our projected revenue in the twelve months ending September 30, 2013 is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense and (ii) the sale of condensate volumes that we collect on our Grand River system. This projection is based on our assumption that we will sell the retained natural gas at Henry Hub pricing as of August 13, 2012, less a basis differential consistent with historical differentials, less contracted transportation costs, and that we will sell the condensate at the NYMEX crude oil strip price as of August 13, 2012, less a basis differential consistent with historical differentials. Fuel retainage volumes are projected according to specific terms embedded within all of the gas gathering agreements for our DFW Midstream customers. We assume that we will sell 8.7 MMcf/d of natural gas at $3.35 per MMBtu for the twelve months ending September 30, 2013, compared to 9.5 MMcf/d of natural gas at $3.60 per MMBtu for the year ended December 31, 2011 and 12.0 MMcf/d of

72

---

Table of Contents

natural gas at $2.84 per MMBtu for the twelve months ended June 30, 2012. Condensate volumes are projected according to historical condensate yields based primarily on projected throughput on our Mamm Creek and South Parachute gathering assets. We assume that we will sell 116 Bbls/d of condensate at $83 per Bbl for the twelve months ending September 30, 2013, compared to 20 Bbls/d of condensate at $85 per Bbl for the year ended December 31, 2011 and 84 Bbls/d of condensate at $89 per Bbl for the twelve months ended June 30, 2012.

•

Sensitivity Analysis.  The actual volume of natural gas that we gather on our systems will influence whether the amount of cash available for distribution for the twelve months ending September 30, 2013 is above or below our forecast. If the actual volume of natural gas we gather on our systems is below our forecast, we may not have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the forecast period. If the actual volume of natural gas we gather on our systems for the twelve months ending September 30, 2013 was 10% lower than our forecast, we would have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to holders of our common units but only        % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units.


Operating and Maintenance Expenses

        Our primary operating and maintenance expenses include labor costs, compression costs, ad valorem and property taxes, utilities and contract services. We estimate that we will incur operating and maintenance expenses of $51.0 million for the twelve months ending September 30, 2013, compared to operating and maintenance expenses of $29.9 million for the year ended December 31, 2011 and $39.8 million for the twelve months ended June 30, 2012. Included in these amounts is compression expense that we incur to operate our electric-drive compression assets on our DFW Midstream system, which varies with (i) our power consumption, which is correlated to the actual throughput on our DFW Midstream system, and (ii) the cost of power. We estimate that we will incur compression costs of $13.1 million, or $0.10 per Mcf, for the twelve months ending September 30, 2013, compared to compression costs of $13.4 million, or $0.11 per Mcf, for the year ended December 31, 2011 and $12.2 million, or $0.10 per Mcf, for the twelve months ended June 30, 2012. Under our gas gathering agreements with our DFW Midstream customers, we physically retain a certain percentage of each customer's throughput that we then sell to offset the power costs we incur. Under our gas gathering agreements with our Grand River customers, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets. Excluding our total compression costs, we estimate that we will incur operating and maintenance expenses of $37.8 million, or $0.11 per Mcf, for the twelve months ending September 30, 2013, compared to operating and maintenance expenses of $16.5 million, or $0.10 per Mcf, for the year ended December 31, 2011 and $27.6 million, or $0.10 per Mcf, for the twelve months ended June 30, 2012. Increased aggregate operating and maintenance expenses for the twelve months ending September 30, 2013 are primarily related to the acquisition of the Grand River system in October 2011 and the additional DFW Midstream operations personnel that were hired during the year ended December 31, 2011 and the twelve months ended June 30, 2012.

        We expect that operating and maintenance expenses will increase in the aggregate, primarily as a result of higher compression expenses, as throughput increases across our gathering systems. We also expect slightly higher operating and maintenance expenses, net of compression costs, primarily due to the hiring of additional operations personnel dedicated to the DFW Midstream system and the Grand River system. Given our volume projections, we expect these increased personnel costs, together with our inflation assumptions for the twelve months ending September 30, 2013, will lead to increased operating and maintenance expenses, net of compression costs, on a dollar per Mcf basis.

73

---

Table of Contents

General and Administrative Expenses

        Our general and administrative expenses will primarily consist of general and administrative expenses that we incur and payments that we make to our general partner in exchange for the provision of general and administrative services, including approximately $2.5 million of expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation.

        We expect our general and administrative expenses to total $21.1 million for the twelve months ending September 30, 2013. This compares to $17.5 million for the year ended December 31, 2011 and $20.9 million for the twelve months ended June 30, 2012. The year ended December 31, 2011 and the twelve months ended June 30, 2012 include certain non-cash, and non-recurring costs that we do not expect to incur in the forecast period, such as one-time, non-cash compensation expense adjustments, transition service expenses associated with our acquisition of the Grand River system from Encana in October 2011, and a higher level of acquisition activity and greenfield diligence expenses incurred in transactions that did not close. Excluding all non-cash compensation, and any non-recurring costs, general and administrative expenses are expected to total $19.3 million for the twelve months ending September 30, 2013, compared with $12.8 million for the year ended December 31, 2011 and $15.4 million for the twelve months ended June 30, 2012. The primary drivers of the increase in our recurring general and administrative expenses for the twelve months ending September 30, 2013, are (i) the inclusion of a full year of general and administrative expenses associated with our acquisition of the Grand River system, including the associated expense of hiring our Grand River asset management and other corporate personnel, and (ii) approximately $2.5 million of incremental expenses related to being a publicly traded partnership.

Depreciation and Amortization Expense

        We estimate that depreciation and amortization expense for the twelve months ending September 30, 2013 will be $37.2 million, compared to $11.4 million for the year ended December 31, 2011 and $25.0 million for the twelve months ended June 30, 2012. Estimated depreciation and amortization expense reflects management's estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization expense is primarily attributable to the inclusion of a full year of depreciation on our Grand River assets and expected capital investments on both the DFW Midstream system and the Grand River system.

Capital Expenditures

        We estimate that total capital expenditures for the twelve months ending September 30, 2013 will be $48.8 million, compared to $667.7 million for the year ended December 31, 2011 and $665.6 million for the twelve months ended June 30, 2012. $590.2 million of our capital expenditures for the year ended December 31, 2011 and the twelve months ended June 30, 2012 were related to the acquisition of the Grand River system in October 2011. Substantially all of our projected capital expenditures are associated with expanding our existing Grand River and DFW Midstream systems. We estimate that total capital expenditures on our Grand River system will be approximately $21.3 million for the twelve months ending September 30, 2013, which will account for approximately 44% of our total capital expenditures during the forecast period, with the DFW Midstream system accounting for the remainder.

•

Maintenance Capital Expenditures.  Historically, we did not make a distinction between maintenance and expansion capital expenditures. We estimate that we will spend $5.5 million for

74

---

Table of Contents

maintenance capital expenditures for the twelve months ending September 30, 2013. The types of maintenance capital expenditures that we expect to incur include expenditures to connect additional pad sites to maintain current volumes and expenditures to replace system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives. It has been customary in the regions in which we operate for producers to bear the cost of connecting individual wells to our pad site meters or central receipt points. In areas where multiple wells are located on a single pad site, such as on the DFW Midstream system, individual wells are connected to our measurement meter on the pad site, which is in turn connected to our gathering pipeline system. In other areas without multiple well pad sites, including certain parts of the Grand River system, individual wells are connected to our nearest central receipt point meter, which in turn is connected to our pipeline gathering system.

•

Expansion Capital Expenditures.  We estimate that our expansion capital expenditures for the twelve months ending September 30, 2013 will total $43.3 million, of which approximately $18.9 million are attributable to the Grand River system and approximately $24.3 million are attributable to the DFW Midstream system. Although we expect that these expenditures will increase throughput over time, we have not assumed any additional volumes during the forecast period related to these expenditures.



•

Grand River system. The majority of our projected expansion capital expenditures on the Grand River system are associated with looping certain sections of pipeline in order to increase system capacity, optimize throughput hydraulics and operating pressures and increase our pad site connections for ongoing low-pressure Mesaverde formation drilling activities.



•

DFW Midstream system. The substantial majority of the expansion capital expenditures associated with the DFW Midstream system during the twelve months ending September 30, 2013 will be to construct new low-pressure pipeline laterals to connect identified pad sites for our customers, including five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P. We are also forecasting expansion capital expenditures during the twelve months ending September 30, 2013 of approximately $5.3 million to install additional compression assets and to complete the construction of several looping pipelines on the DFW Midstream system to increase system capacity to over 450 MMcf/d and to optimize throughput hydraulics and operating pressures.

Financing


•

Amended and Restated Revolving Credit Facility.  Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:



•

permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to be less than 2.50 to 1.00;



•

permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to be above 5.00 to 1.00 (or 5.50 to 1.00 if we have made certain business acquisitions);



•

incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject to customary exceptions for permitted liens;



•

make any investments, subject to customary exceptions for certain permitted investments;



•

engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactions of such types;

75

---

Table of Contents

•

pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants under the amended and restated credit agreement;



•

enter into any swap agreements or power purchase agreements, subject to customary exceptions, such as the entry into swap agreements and power purchase agreements in the ordinary course of business; and



•

enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.

        Repayments of principal under our amended and restated credit facility are not reflected as reductions in estimated cash available for distribution.

•

Cash and Liquidity.  At the closing of this offering, we expect to have $             million of capacity under our amended and restated revolving credit facility after using a portion of the net proceeds of this offering to repay approximately $             million currently outstanding under our amended and restated revolving credit facility. Please read "Use of Proceeds." At the closing of this offering, we expect to have outstanding indebtedness of approximately $             million and a total leverage ratio of approximately 2.0x, which we believe will provide us with sufficient liquidity to fund our anticipated expansion capital expenditures during the forecast period. We intend to fund our forecasted maintenance capital expenditures with operating cash flow. We intend to refinance debt as it comes due, and because our amended and restated credit facility does not require any principal payments until the facility matures in 2016, we have assumed no principal repayments during the forecast period.



•

Interest Expense.  We estimate that our interest expense excluding the effects of amortization of deferred loan costs for the twelve months ending September 30, 2013 will be approximately $7.7 million, compared to $2.5 million for the year ended December 31, 2011 and $10.1 million for the twelve months ended June 30, 2012. The interest expense for these historical periods does not include assumed interest expense related to assumed borrowings to finance capital expenditures. Our projected interest expense is based on an assumed average outstanding debt balance of $207.0 million under our amended and restated revolving credit facility during the forecasted period, including borrowings to finance our projected expansion capital expenditures. We assume a weighted average interest rate of 2.92% during the twelve months ending September 30, 2013. This rate is based on a forecast of LIBOR rates during the period plus the applicable margin as defined in our amended and restated credit agreement. We have also assumed commitment fees of 0.50% for the unused portion of our amended and restated revolving credit facility. We have assumed no interest income with respect to the cash that we maintain on our balance sheet during the forecast period.

Regulatory, Industry and Economic Factors

        Our forecast for the twelve months ending September 30, 2013 is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.



•

There will not be any major adverse change in the midstream energy sector, commodity prices or in market, insurance or general economic conditions.



•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.



•

We will not make any acquisitions or other significant expansion capital expenditures (other than as described above).

76

---

Table of Contents

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

        Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                         , 2012, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through                        , 2012 based on the actual length of the period.

Definition of Available Cash

        Available cash generally means, for any quarter, all cash on hand at the end of that quarter:

•

less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:



•

provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);



•

comply with applicable law, any of our debt instruments or other agreements; or



•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);



•

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

        The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Intent to Distribute the Minimum Quarterly Distribution

        We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $            per unit, or $            on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs

77

---

Table of Contents

and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for a discussion of the restrictions included in our amended and restated revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

        Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $            per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any common or subordinated units that it owns. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.

Operating Surplus and Capital Surplus

General

        All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

        We define operating surplus as:

•

$             million (as described below); plus



•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus



•

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus



•

cash distributions (including incremental distributions on incentive distribution rights) paid on equity issued, other than equity issued in this offering, to finance all or a portion of the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the

78

---

Table of Contents

earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of; plus

•

cash distributions (including incremental distributions on incentive distribution rights) paid on equity issued, other than equity issued in this offering, to pay the construction-period interest on debt incurred, or to pay construction-period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less



•

all of our operating expenditures (as defined below) after the closing of this offering; less



•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less



•

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings.

        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $             million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of ordinary course asset retirements or replacements and (iv) capital contributions received.

        We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, compensation of employees, officers and directors of our general partner, reimbursements of expenses to our general partner and its affiliates, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

•

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);



•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;



•

expansion capital expenditures;



•

payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;

79

---

Table of Contents

•

distributions to our partners; or



•

repurchases of our units, other than repurchases to satisfy obligations under employee benefit plans or reimbursement of expenses of our general partner for purchases of units to satisfy obligations under employee benefit plans.


Capital Surplus

        Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

•

borrowings other than working capital borrowings;



•

sales of our equity and debt securities; and



•

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

        Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

        Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our operating income or operating capacity over the long term. We expect that a primary component of maintenance capital expenditures will include expenditures to connect additional wells to our gathering systems to offset natural declines in production over time and for routine equipment and pipeline maintenance or replacement due to obsolescence.

        Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Expansion capital expenditures include interest payments (and related fees) on debt incurred and issued to finance the construction of such capital improvement and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or operating income.

        Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated between maintenance capital expenditures and expansion capital expenditures by our general partner.

80

---

Table of Contents

Subordination Period

General

        Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $            per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

        Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after                        , 2015, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the related distribution on the general partner interest equaled or exceeded $            (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;



•

the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded (i) the sum of $            (the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during those periods on a fully diluted weighted average basis and (ii) the corresponding distribution on our 2.0% general partner interest; and



•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

        Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after                        , 2013, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the related distribution on the general partner interest equaled or exceeded $            (150.0% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;



•

the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $            (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted weighted average basis and (ii) the distributions made on our 2.0% general partner interest and the incentive distribution rights; and

81

---

Table of Contents

•

there are no arrearages in payment of the minimum quarterly distributions on the common units.


Expiration of the Subordination Period

        When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately and automatically convert into one common unit;



•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.


Definition of Adjusted Operating Surplus

        Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

•

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption "—Operating Surplus and Capital Surplus—Operating Surplus" above); less



•

any net increase in working capital borrowings with respect to that period; less



•

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus



•

any net decrease in working capital borrowings with respect to that period; plus



•

any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the third bullet point above; plus



•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

82

---

Table of Contents

•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

        Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

        Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest at any time without the approval of any person.

        The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

        If for any quarter:

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

83

---

Table of Contents

•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "first target distribution");



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "second target distribution");



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "third target distribution"); and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised,

84

---

Table of Contents

without approval of our unitholders or the Conflicts Committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

        In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner's interest in us immediately prior to the reset election.

        The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

        Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

85

---

Table of Contents

        The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $            .

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be                                     common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $            for the two quarters prior to the reset.

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution

86

---

Table of Contents

rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be                        common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $            . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $            , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $            .

        Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

        We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and



•

thereafter, as if they were distributions from operating surplus.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

        Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the

87

---

Table of Contents

unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;



•

target distribution levels;



•

the unrecovered initial unit price;



•

the number of general partner units comprising the general partner interest; and



•

the per unit arrearage in payment of the minimum quarterly distribution on the common units.

        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be split into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

        If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

88

---

Table of Contents

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

        The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;



•

fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;



•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;



•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

89

---

Table of Contents

        The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

•

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;



•

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and



•

thereafter, 100.0% to our general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

        Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

90

---

Table of Contents

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

        The following table presents as of the dates and for the periods indicated the selected historical consolidated financial and operating data of our Predecessor. On September 3, 2009, we acquired a controlling interest in DFW Midstream Services LLC, which we refer to as our Initial Predecessor for the period prior to such date. We use the term Summit Midstream Predecessor to describe our Predecessor's operations after September 3, 2009. We acquired the Grand River system on October 27, 2011 and we have included its financial results in the financial statements of Summit Midstream Predecessor since the date of acquisition.

        The selected historical consolidated financial data presented as of June 30, 2012 and for the six months ended June 30, 2012 and June 30, 2011 are derived from our unaudited historical condensed financial statements included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2011 and December 31, 2010 and for the period from September 3, 2009 to December 31, 2009, for the year ended December 31, 2011 and the year ended December 31, 2010 have been derived from the audited historical consolidated financial statements of Summit Midstream Predecessor included elsewhere in this prospectus. The selected historical balance sheet data as of December 31, 2009 are derived from the audited historical financial statement of Summit Midstream Predecessor that are not included in this prospectus. The selected historical financial data for the period from January 1, 2009 to September 3, 2009 are derived from the audited historical financial statements of our Initial Predecessor included elsewhere in this prospectus. We acquired our initial assets from Energy Future Holdings Corp. and Chesapeake effective as of September 3, 2009.

        For a detailed discussion of the information presented in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with the historical audited and unaudited consolidated financial statements and related notes of our Predecessor included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information below.

        The following table presents the non-GAAP financial measures of EBITDA and Adjusted EBITDA, which we use in our business as measures of performance and liquidity. We define EBITDA as net income:

•

Plus:



•

interest expense;



•

income tax expense; and



•

depreciation and amortization expense.



•

Less:



•

interest income; and



•

income tax benefit.

        We define Adjusted EBITDA as EBITDA:

•

Plus:



•

non-cash compensation expense; and



•

adjustments related to MVC shortfall payments.

For a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measure" on page 94. For a description of adjustments related to MVC shortfall payments, please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012."

91

---

Table of Contents

92

---

Table of Contents

Non-GAAP Financial Measures

        We include in this prospectus the non-GAAP financial measures of EBITDA and Adjusted EBITDA. We provide a reconciliation of this non-GAAP financial measure to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

EBITDA

        We define EBITDA as net income (loss):

•

Plus:



•

interest expense;



•

income tax expense; and



•

depreciation and amortization expense.



•

Less:



•

interest income; and



•

income tax benefit.

        We define Adjusted EBITDA as EBITDA:

•

Plus:



•

non-cash compensation expense; and

93

---

Table of Contents

•

adjustments related to MVC shortfall payments.

        EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

        (EBITDA and Adjusted EBITDA)

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;



•

the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;



•

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

        (Adjusted EBITDA)

•

the financial performance of our assets without regard to the impact of the timing of MVC shortfall payments under our GGAs or the impact of non-cash compensation expense.

        The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net cash flows provided by operating activities and net income. Our non-GAAP financial measures of EBITDA and Adjusted EBITDA should not be considered as an alternative to net income or cash flows from operating activities. You should not consider EBITDA and Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered as alternatives to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

•

certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;



•

EBITDA and Adjusted EBITDA do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;



•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital needs;



•

although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements; and



•

our computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

        Management compensates for the limitations of EBITDA and Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management's decision-making process.

94

---

Table of Contents

        The following table presents a reconciliation of Adjusted EBITDA to net income and net cash flows provided by (used in) operating activities for each of the periods indicated:

 

---

(1)

For a discussion of adjustments related to shortfall payments, please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the Twelve Months Ended June 30, 2012."

(2)

EBITDA and Adjusted EBITDA for the six months ended June 30, 2012 and for the year ended December 31, 2011 include $0.2 million and $3.2 million, respectively, in transaction costs related to our acquisition of the Grand River system. EBITDA and Adjusted EBITDA for the year ended December 31, 2010 include $1.8 million in settlement expenses related to a dispute with a contractor at the DFW Midstream system. EBITDA and Adjusted EBITDA for the 2009 Summit Midstream Predecessor Period include transaction costs of $3.9 million primarily related to the acquisition of the DFW Midstream system in September 2009. These unusual and non-recurring expenses were included in the calculations of EBITDA and Adjusted EBITDA, and were settled in cash.

(3)

Interest expense presented excludes $0.6 million, $0.6 million and $0.1 million in amortization of deferred loan costs for the year ended December 31, 2011 and for the six months ended June 30, 2012 and 2011, respectively. Interest expense excludes $2.0 million and $5.4 million in paid in kind interest on promissory notes payable to our sponsors for the year ended December 31, 2011 and for the six months ended June 30, 2012, respectively.

95

---

Table of Contents

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

        You should read the following discussion of the financial condition and results of operations of Summit Midstream Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements and related notes of Summit Midstream Partners, LLC, which we refer to as Summit Midstream Predecessor, included elsewhere in this prospectus. We sometimes refer to DFW Midstream Services LLC, or our Initial Predecessor, and Summit Midstream Predecessor collectively as our Predecessor. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

Overview

        We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of June 30, 2012, our gathering systems had approximately 385 miles of pipeline and 147,600 horsepower of compression. During the six months ended June 30, 2012, our systems gathered an average of approximately 909 MMcf/d of natural gas, of which approximately 64% contained natural gas liquids, or NGLs, that were extracted by a third party processor.

        We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

        Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments. Our AMIs cover approximately 330,000 acres in the aggregate, have original terms that range from 10 years to 25 years, and provide that any natural gas producing wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.5 Tcf at June 30, 2012 and, through 2020, average approximately 639 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of June 30, 2012, had a weighted average remaining life of 11.4 years, assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

Our Operations

        Our results are driven primarily by the volumes of natural gas that we gather across our systems. For the year ended December 31, 2011 and the six months ended June 30, 2012, approximately 80% and 84%, respectively, of our revenue was associated with fee-based gathering services that we provided to our customers. Approximately 12% of our revenue was associated with (i) the sale of physical natural gas that we retained from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collected on our Grand River system. We generated the remainder of our revenue by charging certain customers with respect to costs we incurred on their behalf to deliver pipeline quality natural

96

---

Table of Contents

gas to third-party pipelines and costs we incurred to operate electric-drive compression on the Grand River system.

        We contract with producers to gather natural gas from pad sites and central receipt points connected to the Grand River system and our gathering system in the Barnett Shale, which we refer to as the DFW Midstream system. These receipt points are connected to our gathering pipelines through which we compress natural gas and deliver it to third-party processing plants or downstream pipelines for ultimate delivery to end users.

        We currently provide substantially all of our gathering services under long-term, fee-based gas gathering agreements, which limit our direct commodity price exposure, and we do not take title to the natural gas we gather on behalf of our customers. Under these agreements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather. We are party to eight, long-term gas gathering agreements with producers in the Barnett Shale and, in connection with our acquisition of the Grand River system from a subsidiary of Encana in October 2011, we entered into three, long-term gas gathering agreements with Encana and assumed six gas gathering agreements with five other producers, three of which are long-term agreements.

        These agreements provide us with a revenue stream that is not subject to direct commodity price risk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. On the Grand River system, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

        We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling or temporarily shut-in production due to persistently low commodity prices, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers. Please read below and "Risk Factors—Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and adversely affecting our revenues and cash available to make distributions to you over the long-term" for additional information regarding the recent decline in natural gas prices and the impact it has had on our customers and our operations.

        We have exposure to both liquids-rich and "dry" gas regions and we believe that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions in the future. Dry gas regions contain natural gas reserves that are primarily comprised of methane, as compared to liquids-rich regions that contain NGLs in addition to methane.

        In the Piceance Basin, our Grand River system benefits from its exposure to liquids-rich gas production from the Mesaverde formation. The attractive economics associated with the production from this formation, combined with our minimum volume commitments from major producers in the area, provide us with stable cash flows and visible growth in the future. In addition, certain of our customers have joint venture agreements in place that provide for the development of portions of the Piceance Basin in our AMIs utilizing third-party funds. We believe the drilling activity from these partnerships will benefit our Grand River system. The Grand River system also serves the emerging Mancos and Niobrara formations, which we expect will become more active to the extent that natural gas prices increase.

        Our DFW Midstream system benefits from its AMIs that cover the most prolific dry gas area of the Barnett Shale. We believe that this area offers our customers a compelling opportunity to maximize drilling economics due to the high estimated ultimate recovery of natural gas per well and relatively low drilling costs when compared to other dry gas resource basins. While recent market prices for natural gas have resulted in reduced drilling activity in the Barnett Shale, a significant number of wells

97

---

Table of Contents

remain in various stages of completion in our AMIs and on pad sites that have already been connected to the DFW Midstream system. These wells represent an opportunity to increase throughput on the DFW Midstream system at minimal incremental capital costs. In addition, because of the urban environment in which the DFW Midstream system is located, we expect that this area will continue to be developed by our customers using a high-density pad site drilling strategy that is designed to support multiple wells from a single location. Instead of constructing pipelines to multiple wells, we connect to an individual pad site, some of which can accommodate up to 30 wells, and gather all of the natural gas produced at that site, thus minimizing our future capital expenditures. This pad site strategy substantially increases the efficiency of both the producers' drilling activities as well as our gathering activities and economics.

How We Evaluate Our Operations

        Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include (i) throughput volume, (ii) operations and maintenance expenses, (iii) Adjusted EBITDA and (iv) distributable cash flow. We manage our business and analyze our results of operations as a single business segment.

Throughput Volume

        The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River and DFW Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

        We must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas is impacted by:

•

successful drilling activity within our AMIs;



•

the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;



•

the number of new pad sites in our AMIs awaiting lateral connections;



•

our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and



•

our ability to gather natural gas that has been released from commitments with our competitors.

        We actively monitor producer activity in the areas served by our gathering systems to pursue new supply opportunities.

Operations and Maintenance Expenses

        We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs,

98

---

Table of Contents

compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems, but may fluctuate depending on the activities performed during a specific period. The majority of our compressors in the Barnett Shale are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our Barnett Shale customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain Barnett Shale customers to deliver pipeline quality natural gas to third-party pipelines. In the Piceance Basin, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

        We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define Adjusted EBITDA as EBITDA plus non-cash compensation expense and adjustments related to MVC shortfall payments. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measures." Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures, to analyze our performance and liquidity. Distributable cash flow will not reflect changes in working capital balances.

        EBITDA, Adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

(EBITDA and Adjusted EBITDA)

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;



•

the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;



•

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

(Adjusted EBITDA)

•

the financial performance of our assets without regard to the impact of the timing of MVC shortfall payments under our GGAs or the impact of non-cash compensation expense.

(Distributable Cash Flow)

•

the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

99

---

Table of Contents

Note Regarding Non-GAAP Financial Measures

        EBITDA, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Net income and net cash flows provided by operating activities are the GAAP measures most directly comparable to EBITDA, Adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider EBITDA, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measures."

General Trends and Outlook

        Our business has been, and we expect our future business to continue to be, affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural gas supply and demand dynamics

        Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $3.21 per MMBtu as of July 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage, warm winter weather and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration ("EIA"), average annual natural gas production in the United States increased 13.9% from 55.2 Bcf/d to 62.9 Bcf/d from 2008 to 2011. Over the same time period, natural gas consumption increased only 4.5% to 66.6 Bcf/d. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.8 Tcf as of August 5, 2011 to approximately 3.2 Tcf as of August 3, 2012 due to the unseasonably warm winter of 2011-2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 430 as of July 31, 2012 according to Smith Bits, as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

        Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in December 2008, 49% of the electricity in the United States was generated by coal-fired power plants and in December 2011, 39% of the electricity in the United States was generated by coal-fired power plants. In January 2012, the EIA projected total annual domestic

100

---

Table of Contents

consumption of natural gas to increase from approximately 22.9 Tcf in 2009 to approximately 26.6 Tcf in 2035. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2035 to 27.9 Tcf. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the United States.

Growth in production from U.S. shale plays

        Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds). While the EIA expects total domestic natural gas production to grow from 20.6 Tcf in 2009 to 27.9 Tcf in 2035, it expects shale gas production to grow to 13.6 Tcf in 2035, or 49% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics as compared to most conventional plays.

        In recent years, well-capitalized producers have leased large acreage positions in the Piceance Basin, the Barnett Shale and other unconventional resource plays. To help fund their drilling program in many of these areas, including in the Piceance Basin and the Barnett Shale, a number of producers have also entered into joint venture arrangements with large international operators and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin, the Barnett Shale and other unconventional resource plays, which we believe will result in sustained drilling activity.

        As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.

Interest rate environment

        The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Rising operating costs and inflation

        The current high level of natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

101

---

Table of Contents

Results of Operations—Combined Overview

        The following table and discussion presents certain historical consolidated financial data of our Predecessor for the periods indicated.

102

---

Table of Contents

Items Affecting the Comparability of Our Financial Results

        The historical results of operations of our Predecessor may not be comparable to our future results of operations for the reasons described below:

•

Because we acquired our initial interest in the DFW Midstream system from Texas Competitive Electric Holdings Company, LLC ("TCEH"), an indirect subsidiary of Energy Future Holdings Corp., effective as of September 3, 2009, the financial and operational data for 2009 that is presented and discussed in this prospectus is generally bifurcated between the period that our Initial Predecessor owned those assets and the period from the acquisition of those assets by Summit Midstream Predecessor through December 31, 2009.



•

The historical consolidated financial statements and related notes of our Initial Predecessor:



•

have been carved out of the accounting records maintained by Energy Future Holdings and its subsidiaries. Certain accounts such as trade accounts receivables, accounts payable, pre-paid expenses and certain accrued liabilities relating to the activities of our Initial Predecessor were recorded on the books of other Energy Future Holdings entities and estimates of those accounts have been included in the consolidated financial statements;



•

include an estimate for general and administrative ("G&A") expenses, as Energy Future Holdings did not allocate any of the central finance and administrative costs to this operating entity;



•

reflect the operation of the DFW Midstream system with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate it. Please read "Business—Business Strategies;" and



•

do not include any results from certain natural gas gathering assets that we acquired from Chesapeake Energy Corporation on September 3, 2009 that are included in the DFW Midstream system.

103

---

Table of Contents

•

The historical consolidated financial statements and related notes of Summit Midstream Predecessor:



•

reflect a 75% ownership interest in the entity we acquired from TCEH from September 4, 2009 to June 18, 2010, the date on which Summit Midstream Predecessor purchased the remaining 25% membership interest from TCEH for $90.7 million;



•

include transaction expenses of $3.9 million in 2009 that we incurred in connection with our formation and our initial acquisition of assets. These expenses include an aggregate of $2.2 million paid to Energy Capital Partners and $1.7 million paid to third parties for strategic, advisory, management, legal, and consulting services;



•

include charges associated with a transition services agreement that we entered into with Energy Future Holdings effective September 3, 2009. Under the terms of the transition services agreement, we paid Energy Future Holdings $38,700, $0.1 million and $0.1 million for the years ended December 31, 2011 and 2010 and the period from September 3, 2009 through December 31, 2009, respectively; and



•

do not include any results from the acquisition of the Grand River system prior to November 2011.



•

We anticipate incurring approximately $2.5 million of G&A expense attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. These incremental G&A expenses are not reflected in the historical consolidated financial statements of our Initial Predecessor or Summit Midstream Predecessor.



•

Following the closing of this offering, we intend to make cash distributions to our unitholders equal to our minimum quarterly distribution of $             per unit per quarter ($             per unit on an annualized basis). Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our amended and restated revolving credit facility and future issuances of equity and debt securities. Historically, Summit Midstream Predecessor largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy its capital expenditure requirements.


Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

        Volume.     Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 606.2 MMcf/d, or 200%, from 303.2 MMcf/d for the six months ended June 30, 2011 to 909.4 MMcf/d for the six months ended June 30, 2012. This increase is due to the continued development of the DFW Midstream system and the acquisition of the Grand River system. There were 311 wells and 62 drilling pad sites and 220 wells and 52 drilling pad sites connected to the DFW Midstream system as of June 30, 2012 and 2011, respectively. The DFW Midstream system included 109 miles and 97 miles of pipeline as of June 30, 2012 and 2011, respectively. Throughput volumes for the DFW Midstream system averaged 325.0 MMcf/d for the six months ended June 30, 2012. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 584.4 MMcf/d for the six months ended June 30, 2012.

104

---

Table of Contents

        Revenue.     Total revenue increased $34.0 million, or 81%, from $41.9 million for the six months ended June 30, 2011 to $75.9 million for the six months ended June 30, 2012. Gathering services and other fees increased $31.6 million, or 85%, from $37.0 million for the six months ended June 30, 2011 to $68.6 million for the six months ended June 30, 2012. This increase was primarily the result of increased throughput volumes on the DFW Midstream system and the acquisition of the Grand River system in October 2011, offset by a decrease of $0.22 per Mcf, or 36%, in the average throughput rates from $0.61 per Mcf for the six months ended June 30, 2011 to $0.38 per Mcf for the six months ended June 30, 2012. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $29.8 million for the six months ended June 30, 2012. Natural gas and condensate sales increased $2.0 million, or 40%, from $5.0 million for the six months ended June 30, 2011 to $7.0 million for the six months ended June 30, 2012. Revenue associated with condensate sales for the Grand River system was $2.1 million for the six months ended June 30, 2012.

        Operations and maintenance expense.     Operations and maintenance expense increased $9.9 million, or 77%, from $12.8 million for the six months ended June 30, 2011 to $22.7 million for the six months ended June 30, 2012. This increase was primarily the result of operations and maintenance expense for the Grand River system of $12.1 million for the six months ended June 30, 2012. Ad valorem taxes increased approximately $0.8 million on the DFW Midstream system for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. Compressor related expenses decreased $0.6 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 due to cancellation of a third-party compressor operating agreement in the fourth quarter of 2011.

        General and administrative ("G&A") expense.     G&A expense increased $3.4 million, or 46%, from $7.4 million for the six months ended June 30, 2011 to $10.8 million for the six months ended June 30, 2012. Salary and benefit expenses increased $2.0 million, or 71%, from $2.9 million for the six months ended June 30, 2011 to $4.9 million for the six months ended June 30, 2012 due to increased headcount to support our growth. Insurance related costs increased $0.6 million and employee related costs increased $0.6 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 as a result of the acquisition of the Grand River system in October 2011. Business development expenses increased $0.6 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increase in G&A expenses was partially offset by a decrease in non-cash unit based compensation for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. Non-cash unit based compensation expense relative to net profits interests held by certain current and former members of management decreased $0.5 million, or 27%, from $1.9 million for the six months ended June 30, 2011 to $1.4 million for the six months ended June 30, 2012.

        Depreciation and amortization expense.     Depreciation and amortization expense increased $13.6 million, or 400%, from $3.4 million for the six months ended June 30, 2011 to $17.0 million for the six months ended June 30, 2012. This increase was primarily the result of the depreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system during 2011 and the acquisition of the Grand River system in October 2011. Depreciation and amortization expense for the Grand River system was $11.3 million for the six months ended June 30, 2012.

        Interest expense and affiliated interest expense.     Interest expense increased $8.1 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This increase was primarily the result of entering into our revolving credit facility in May 2011 and issuing $200 million of promissory notes to our sponsors in connection with the acquisition of the Grand River system. We did not have outstanding promissory notes during the six months ended June 30, 2011.

105

---

Table of Contents

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        Volume.     Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 296.4 MMcf/d, or 218%, from 135.9 MMcf/d for the year ended December 31, 2010 to 432.3 MMcf/d for the year ended December 31, 2011. This increase was due to the continued development of the DFW Midstream system. There were 276 wells and 58 drilling pad sites and 160 wells and 33 drilling pad sites connected to the DFW Midstream system as of December 31, 2011 and 2010, respectively. The DFW Midstream system included 104 miles and 83 miles of pipeline as of December 31, 2011 and December 31, 2010, respectively. Throughput volumes for the DFW Midstream system averaged 332.7 MMcf/d for the year ended December 31, 2011. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 595.9 MMcf/d for the two months that the Grand River system was included in our financial results for the year ended December 31, 2011.

        Revenue.     Total revenue increased $71.9 million, or 227%, from $31.7 million for the year ended December 31, 2010 to $103.6 million for the year ended December 31, 2011. Gathering services and other fees increased $62.1 million, or 211%, from $29.4 million for the year ended December 31, 2010 to $91.4 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system, offset by a decrease of $0.04 per Mcf, or 7%, in the average throughput rates from $0.56 per Mcf for the year ended December 31, 2010 to $0.52 per Mcf for the year ended December 31, 2011. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $11.0 million for the two months that the Grand River system was included in our financial results for the year ended December 31, 2011. Natural gas and condensate sales increased $9.9 million, or 391%, from $2.5 million for the year ended December 31, 2010 to $12.4 million for the year ended December 31, 2011. The increase in revenue attributable to natural gas and condensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the Grand River system was $0.6 million for the two months ended December 31, 2011.

        Operations and maintenance expense.     Operations and maintenance expense increased $20.4 million, or 214%, from $9.5 million for the year ended December 31, 2010 to $29.9 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors increased $9.1 million, or 206%, from $4.4 million for the year ended December 31, 2010 to $13.5 million for the year ended December 31, 2011 due to increased volumes and the associated increased power cost to operate the compression. Operations and maintenance expenses for the Grand River system were $3.9 million for the two months that the Grand River system was included in our financial results for the year ended December 31, 2011.

        General and administrative expense.     G&A expense increased $7.4 million, or 74%, from $10.0 million for the year ended December 31, 2010 to $17.5 million for the year ended December 31, 2011. We recorded non-cash compensation expense of $3.4 million for the year ended December 31, 2011 relative to profits interests held by certain members of management. We did not record non-cash compensation expense for the year ended December 31, 2010. Salary and benefit expenses increased $2.0 million, or 45%, from $4.3 million for the year ended December 31, 2010 to $6.3 million for the year ended December 31, 2011 due to increased headcount to support our growth. We did not have these expenses for the year ended December 31, 2010. Due diligence costs relative to potential asset acquisitions were $1.3 million in 2011 compared to insignificant due diligence costs in 2010. The increase in G&A expenses was offset by decreases in legal expenses for the year ended December 31, 2011 compared to the year ended December 31, 2010. Legal expenses decreased $2.0 million in 2011

106

---

Table of Contents

primarily as the result of decreased legal activities relative to relationships with contractors and sub-contractors associated with the DFW Midstream system. We had $1.8 million in settlement expenses in 2010 related to a dispute with a contractor at the DFW Midstream system.

        Transaction costs.     Transaction costs were $3.2 million for the year ended December 31, 2011. These transaction costs were primarily related to the acquisition of the Grand River system. We did not have transaction costs for the year ended December 31, 2010.

        Depreciation and amortization expense.     Depreciation and amortization expense increased $7.5 million, or 192%, from $3.9 million for the year ended December 31, 2010 to $11.4 million for the year ended December 31, 2011. This increase was primarily the result of the depreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system in 2011. Depreciation and amortization expense for the Grand River system was $3.2 million for the two months that the Grand River system was included in our financial results for the year ended December 31, 2011.

        Interest expense and affiliated interest expense.     Interest expense increased $3.1 million for the year ended December 31, 2011. This increase was primarily the result of entering into our revolving credit facility in May 2011 and the related amortization of deferred loan costs of $0.6 million and issuing $200 million of promissory notes to our sponsors in connection with the acquisition of the Grand River system. We did not have a revolving credit facility or outstanding promissory notes in 2010 and, therefore, we had no interest expense for the year ended December 31, 2010.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

        Volume.     Throughput volumes increased 120.0 MMcf/d, or 755%, from 15.9 MMcf/d for the 2009 Initial Predecessor Period to 135.9 MMcf/d for the year ended December 31, 2010. Throughput volumes increased 112.4 MMcf/d, or 478%, from 23.5 MMcf/d for the 2009 Summit Midstream Predecessor Period to 135.9 MMcf/d for the year ended December 31, 2010. Throughput volumes increased significantly for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period due to the continued development of the DFW Midstream system. There were 160 wells and 33 drilling pad sites and 20 wells and 4 drilling pad sites connected to the DFW Midstream system as of December 31, 2010 and December 31, 2009, respectively. The DFW Midstream system included 83 miles and 12 miles of pipeline as of December 31, 2010 and December 31, 2009, respectively.

        Revenue.     Revenue increased $28.0 million, or 770%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $31.7 million for the year ended December 31, 2010. Gas gathering revenue increased $25.8 million, or 710%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $29.4 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Average throughput rates decreased $0.01 per Mcf, or 2%, from $0.57 per Mcf for the 2009 Summit Midstream Predecessor Period to $0.56 per Mcf for the year ended December 31, 2010. Natural gas and condensate sales were $2.5 million for the year ended December 31, 2010. Revenue for the year ended December 31, 2010 included sales of natural gas that we retain from DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale.

        Operations and maintenance expense.     Operations and maintenance expense increased $7.3 million, or 341%, from $1.0 million for the 2009 Initial Predecessor Period and $1.1 million for the 2009 Summit Midstream Predecessor Period to $9.5 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system.

107

---

Table of Contents

Utility expense for our electric drive compressors were $4.4 million for the year ended December 31, 2010. Utility expense for the 2009 Initial Predecessor Period and for the 2009 Summit Midstream Predecessor Period was insignificant. The remaining increase in operations and maintenance expense for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period was primarily the result of additional throughput on the DFW Midstream system and additional compression being placed into service.

        General and administrative expense.     G&A expense increased $6.5 million, or 184%, from $0.6 million for the 2009 Initial Predecessor Period and $2.9 million for the 2009 Summit Midstream Predecessor Period to $10.0 million for the year ended December 31, 2010. Legal expenses increased $2.0 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period primarily as the result of legal activities relative to relationships with contractors and sub-contractors associated with the DFW Midstream system. The remaining increase in G&A expenses for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period is the result of our ownership of the DFW Midstream system for the full year 2010. We acquired our initial assets of our DFW Midstream system effective as of September 3, 2009. Additionally, we increased our headcount in 2010 compared to 2009 as we continued construction and development of the DFW Midstream system.

        Transaction costs.     Transaction costs were $3.9 million for the 2009 Summit Midstream Predecessor Period. These transaction costs were primarily related to the acquisition of the DFW Midstream system in September 2009. We did not have transaction costs for the 2009 Initial Predecessor Period or the year ended December 31, 2010.

        Depreciation and amortization expense.     Depreciation and amortization expense increased $2.6 million, or 216%, from $0.9 million for the 2009 Initial Predecessor Period and $0.3 million for the 2009 Summit Midstream Predecessor Period to $3.9 million for the year ended December 31, 2010. This increase was primarily the result of the depreciation associated with assets placed into service in connection with the expansion and development of the DFW Midstream system in 2010.

        Interest expense.     Interest expense decreased $0.2 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. Interest expense for the 2009 Initial Predecessor Period included $0.2 million related to an intercompany capital allocation charge during the ownership of the DFW Midstream system by our Initial Predecessor. We did not have an intercompany capital allocation charge for the year ended December 31, 2010.

Liquidity and Capital Resources

        Since the acquisition of our initial assets in September 2009, our sources of liquidity have included cash generated from operations, equity investments by our sponsors, Energy Capital Partners and GE Energy Financial Services, and borrowings under our revolving credit facility.

        Following the closing of this offering we expect our sources of liquidity to include:

•

cash generated from operations;



•

borrowings under our amended and restated revolving credit facility; and



•

issuances of debt and equity securities.

        We believe that the cash generated from these sources will be sufficient to allow us to distribute the minimum quarterly distribution to all of our unitholders and the corresponding distribution on our 2.0% general partner interest and to meet our requirements for working capital and capital expenditures for the foreseeable future.

108

---

Table of Contents

Cash Flows

        The following table reflects cash flows for the applicable periods:

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

        Operating activities.     Cash flows from operating activities increased by $25.9 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increase in cash flows from operating activities is a direct result of the increase in volumes on the DFW Midstream system for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 and the inclusion of operations on the Grand River system for the six months ended June 30, 2012.

        Investing activities.     Cash flows used for investing activities decreased by $2.1 million, or 8%, from $26.5 million for the six months ended June 30, 2011 to $24.4 million for the six months ended June 30, 2012. Capital expenditures on the DFW Midstream system decreased $15.0 million, or 57%, from $26.5 million for the six months ended June 30, 2011 to $11.5 million for the six months ended June 30, 2012. Capital expenditures on the Grand River system were $8.0 million for the six months ended June 30, 2012.

        Financing activities.     Cash flows from financing activities were $19.4 million for the six months ended June 30, 2011 and consisted of $15.0 million of capital contributions from Energy Capital Partners to support capital needs related to the construction of the DFW Midstream system. Summit Midstream Predecessor closed on our revolving credit facility in May 2011. Summit Midstream Predecessor made a distribution to Energy Capital Partners of $132.9 million of the $142.0 million drawn at closing. Summit Midstream Predecessor incurred $4.7 million of deferred loan costs for the six months ended June 30, 2011. Cash flows used in financing activities were $9.8 million for the six months ended June 30, 2012. Effective May 7, 2012, we amended and restated our revolving credit facility to increase our borrowing capacity from $285.0 million to $550.0 million. On May 8, 2012, we borrowed $163.0 million under this facility and used $160.0 million of those borrowings to repay amounts outstanding under the promissory notes payable to our sponsors. We repaid $8.0 million under our amended and restated revolving credit facility during the six months ended June 30, 2012. No capital contributions were made during the six months ended June 30, 2012. Cash flows used in financing activities for the six months ended June 30, 2012 included $4.8 million of deferred loan costs and initial public offering costs.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        Operating activities.     Cash flows from operating activities increased by $30.4 million, or 318%, from $9.6 million for the year ended December 31, 2010 to $40.0 million for the year ended December 31, 2011. The increase in cash flows from operating activities is a direct result of the significant increase in volumes on the DFW Midstream system during 2011 compared to 2010 and the inclusion of two months of operations on the Grand River system for the year ended December 31, 2011.

109

---

Table of Contents

        Investing activities.     Cash flows used for investing activities increased by $514.0 million, or 334%, from $153.7 million for the year ended December 31, 2010 to $667.7 million for the year ended December 31, 2011. The increase in cash flows used for investing activities is primarily due to the acquisition of the Grand River system for $589.5 million. Capital expenditures decreased by $79.2 million, or 49%, from $154.0 million for the year ended December 31, 2010 to $74.8 million for the year ended December 31, 2011. Capital expenditures in 2010 were higher due to the installation and commissioning of compressor stations on the DFW Midstream system.

        Financing activities.     Cash flows from financing activities increased by $519.7 million, or 455%, from $114.1 million for the year ended December 31, 2010 to $633.8 million for the year ended December 31, 2011. The increase in cash flows from financing activities is primarily due to the acquisition of the Grand River system. Summit Midstream Predecessor received equity contributions of $410.0 million and a $200.0 million non-recourse loan from Energy Capital Partners and GE Energy Financial Services to acquire the Grand River system. Summit Midstream Predecessor closed on our revolving credit facility in May 2011. Upon closing the revolving credit facility, Summit Midstream Predecessor made a distribution to Energy Capital Partners of $132.9 million of the $142.0 million drawn at closing.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

        Operating activities.     Cash flows from operating activities increased by $15.2 million from $0.6 million for the 2009 Initial Predecessor Period and $(6.2) million for the 2009 Summit Midstream Predecessor Period to $9.6 million for the year ended December 31, 2010. The increase in cash flows from operating activities is related to the increased volumes on the DFW Midstream system during 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. The increase in volumes resulted in an increase of net income by $15.6 million, from $(0.8) million for the 2009 Initial Predecessor Period and $(6.6) million for the 2009 Summit Midstream Predecessor Period to $8.2 million for the year ended December 31, 2010.

        Investing activities.     Cash flows used for investing activities increased by $48.5 million, or 46%, from $40.8 million for the 2009 Initial Predecessor Period and $64.4 million for the 2009 Summit Midstream Predecessor Period to $153.7 million for the year ended December 31, 2010. The cash used for investing activities increased due to the installation and commissioning of the compressor stations on the DFW Midstream system during 2010.

        Financing activities.     The cash flows from financing activities during the 2009 Initial Predecessor Period, the 2009 Summit Midstream Predecessor Period and the year ended December 31, 2010 were capital contributions from Energy Capital Partners. During the 2009 Summit Midstream Predecessor Period, Energy Capital Partners contributed $107.0 million at formation and then contributed an additional $27.9 million to support capital needs related to the construction of the DFW Midstream system. In the year ended December 31, 2010, Energy Capital Partners contributed $194.1 million in support of the continued growth and construction of the DFW Midstream system. In June 2010, we purchased the remainder of Energy Future Holdings' membership interests related to the DFW Midstream system for $90.7 million, which was funded with the capital contributed by Energy Capital Partners.

Off-Balance Sheet Arrangements

        We do not have any off-balance sheet arrangements.

110

---

Table of Contents

Capital Requirements

        The natural gas gathering segment of the midstream energy business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

•

maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or



•

expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term.

        For the year ended December 31, 2011, our total capital expenditures were $667.7 million. $589.5 million of the capital expenditures in 2011 were related to our acquisition of the Grand River system in October 2011. The remainder were primarily associated with the construction of new pipeline infrastructure to connect new pad sites on our DFW Midstream system and to connect new pad sites and central receipt points on our Grand River system. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We have estimated, however, that approximately $3.1 million of these capital expenditures were maintenance capital expenditures.

        We are forecasting $82.2 million in capital expenditures for the year ending December 31, 2012, of which $77.0 million represents expansion capital expenditures and $5.3 million represents maintenance capital expenditures. Our 2012 budgeted expansion capital expenditures include:

•

$18.3 million related to the installation of additional compression assets and construction of several looping pipelines on the DFW Midstream system in order to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures;



•

$17.9 million to construct pipeline laterals and tie in additional pad sites for customers on the DFW Midstream system;



•

$10.0 million associated with the procurement and installation of pad site meter equipment at approximately 400 existing pad sites on the Grand River system;



•

$8.9 million to expand and improve hydraulic efficiency of our assets in the Mamm Creek field on the Grand River system;



•

$5.7 million to connect five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P; and



•

$5.3 million related to the construction of medium-pressure pipelines and the installation of additional compression-related assets in the Orchard field on the Grand River system.

        As of June 30, 2012, we have spent approximately $21.7 million of our 2012 expansion capital budget.

        We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities.

111

---

Table of Contents

Distributions

        We intend to pay a quarterly distribution at an initial rate of $            per unit, which equates to an aggregate distribution of $             million per quarter, or $             million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering and the related distributions on our 2.0% general partner interest. We do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our Amended and Restated Revolving Credit Facility

        Effective May 7, 2012, we amended and restated our revolving credit facility with a syndicate of lenders to increase our borrowing capacity from $285 million to $550 million. Substantially all of our assets are pledged as collateral under our amended and restated revolving credit facility. The amended and restated revolving credit facility matures in May 2016 and, at our option, borrowings thereunder bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%.

        Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:

•

permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to be less than 2.50 to 1.00;



•

permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to be above 5.00 to 1.00 (or 5.50 to 1.00 if we have made certain business acquisitions);



•

incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject to customary exceptions for permitted liens;



•

make any investments, subject to customary exceptions for certain permitted investments;



•

engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactions of such types;



•

pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants under the amended and restated credit agreement;



•

enter into any swap agreements or power purchase agreements, subject to customary exceptions, such as the entry into swap agreements and power purchase agreements in the ordinary course of business; and



•

enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.

        As of June 30, 2012, we were in compliance with the financial and other covenants in our amended and restated revolving credit facility.

        Our amended and restated revolving credit facility contains events of default customary for credit facilities of this size and nature, including, but not limited to (i) events of default resulting from our failure to comply with covenants, (ii) the occurrence of a change of control, (iii) the institution of insolvency or similar proceedings against us, (iv) the occurrence of a default under any other material indebtedness we may have and (v) the termination of any one or more or our gas gathering agreements

112

---

Table of Contents

accounting for 25% or more of our revenue that results in a material adverse effect (as defined in the amended and restated credit agreement) and for which a replacement gas gathering agreement with substantially similar terms is not entered into within 30 days after such termination. Upon the occurrence of an event of default, subject to the terms and conditions of our amended and restated revolving credit facility, the lenders may, in addition to exercising other remedies, declare any outstanding principal of our revolving credit facility debt, together with accrued and unpaid interest, to be immediately due and payable.

        In addition to the uses described in "Use of Proceeds," we expect borrowings under our amended and restated revolving credit facility to be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) capital expenditures. There was $347.2 million drawn under our amended and restated revolving credit facility at August 20, 2012.

Promissory Notes Payable to Sponsors

        In connection with our acquisition of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million and had an 8% interest rate and a maturity date of October 27, 2013. Summit Investments exercised its option to make a payment in kind for all interest due as of June 30, 2012. The amount of interest paid in kind and accrued to the balance of the notes as of June 30, 2012 was $9.2 million. During 2011 and the six months ended June 30, 2012, Summit Investments capitalized $0.9 million of the $2.9 million interest expense and $0.9 million of the $6.3 million interest expense, respectively, related to costs incurred on capital projects under construction. As of June 30, 2012, the aggregate carrying value of these notes approximated the fair value.

        The promissory notes payable to our sponsors were repaid in full on July 2, 2012.

Credit Risk and Customer Concentration

        We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. A significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. Chesapeake, Carrizo, TOTAL and Energy Transfer Fuels each accounted for more than 10% of our $103.6 million in consolidated revenue for the year ended December 31, 2011, accounting for 34%, 17%, 10% and 12%, respectively, of our consolidated revenue for that year. Encana, Carrizo and Chesapeake accounted for approximately 29%, 16% and 16%, respectively, of our revenue for the six months ended June 30, 2012. Although we have contractual arrangements with each of these counterparties of varying duration, if one or more of these customers were to default on their contractual obligations or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.

113

---

Table of Contents

Contractual Obligations

        The table below summarizes our contractual obligations and other commitments as of December 31, 2011:

Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

        We have exposure to changes in interest rates on our indebtedness associated with our amended and restated revolving credit facility. The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

        Summit Midstream Predecessor entered into our revolving credit facility in May 2011, which was amended and restated on May 7, 2012. A hypothetical increase or decrease in interest rates of 1.0% would have increased or decreased, respectively, our interest expense by $1.0 million and $0.9 million for the year ended December 31, 2011 and for the six months ended June 30, 2012, respectively.

Commodity Price Risk

        Because we currently generate a substantial majority of our revenues pursuant to long-term, fixed-fee gas gathering agreements that include minimum volume commitments and AMIs, our only direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system and (iii) the sale of condensate volumes that we collect on the Grand River system. Our gas gathering agreements with our Barnett Shale customers permit us to retain a certain quantity of natural gas that is intended to offset the power costs we incur to operate our electric-drive compression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate

114

---

Table of Contents

based on prevailing natural gas prices at the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas sales. We do not enter into risk management contracts for speculative purposes.

Impact of Seasonality

        Our results of operations on our gathering systems are not materially affected by seasonality.

Critical Accounting Policies and Estimates

        In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities as of the balance sheet date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses, including fair value measurements and disclosure of contingencies, during the reporting period. Our actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the accounting policies currently underlying our most significant financial statement items:

Contingencies

        Our consolidated financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.

Depreciation

        Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property, plant and equipment and revise our estimates. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.

Property, Plant and Equipment

        Property, plant, and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirement of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in the statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

115

---

Table of Contents

Impairment of Long-Lived Assets

        Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposal of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows.

Goodwill

        Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment using a two-step quantitative test. The first step compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired. If the fair value does not exceed the carrying amount, the second step compares the impaired fair value to the carrying value of the reporting unit. If the carrying amount of a reporting unit's goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment loss.

Compensatory Awards

        Certain of our current and former employees were granted Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC. We refer to these interests collectively as the net profits interests. The net profits interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested net profits interests. The net profits interests are accounted for as compensatory awards. The net profits interests vest ratably over four to five years, and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Summit Midstream Partners LLC Agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the net profits interests as of the respective grant dates. The net profits interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the net profits interests: (a) assumptions underlying the enterprise value used in connection with the option pricing method, including the discount rate applied to estimated future cash flows, forecasted gathering volumes, revenues and costs, equity performance relative to peer group members, equity market risk premium, enterprise-specific risk premium, and terminal growth rates; (b) holding period restrictions; (c) discounts for lack of marketability; and (d) expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

116

---

Table of Contents

Revenue Recognition

        We earn revenue from natural gas gathering services provided to natural gas producers and record such revenue as gathering services and other fees. We also earn revenue from the sale of physical natural gas retained from our customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. We record this revenue as natural gas and condensate sales. We record costs incurred which are reimbursed by our customers, on a gross basis in the consolidated statement of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

        Our gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from our customers. Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. Under certain gas gathering agreements, our customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC, ranging from twelve months to nine years.

        Billings to customers for obligations under their MVCs are recorded as deferred revenue. We recognize deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related MVC have either (i) been satisfied through the gathering of future excess volumes, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable GGA. We classify deferred revenue as short-term for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less.

117

---

Table of Contents

INDUSTRY OVERVIEW

General

        The midstream natural gas industry is the link between the exploration and production of natural gas from the wellhead or lease and the delivery of the natural gas and its other components to end-use markets. Companies within this industry create value at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and natural gas liquids, or NGLs, and then routing the separated dry gas and NGL streams for delivery to end-markets or to the next intermediate stage of the value chain.

        The following diagram illustrates the groups of assets commonly found along the natural gas value chain:

Midstream Services

        The range of services utilized by midstream natural gas service providers are generally divided into the following categories:

Gathering

        At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression

        Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression,

118

---

Table of Contents

volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration

        Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing

        The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation

        The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.

Transportation and Storage

        Once the raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.

Contractual Arrangements

        Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical types of contracts are described below.

119

---

Table of Contents

Fee-Based

        Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure.

Percent-of-Proceeds

        Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.

Keep-Whole

        Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processor compensates the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

        There are two forms of contracts utilized in the transportation and storage of natural gas:

Firm

        Firm service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a "demand" or "capacity reservation" fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas gathered. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.

Interruptible

        Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Market Fundamentals

Natural Gas Demand

        Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 25% of all energy used in the United States in 2010, representing 24 Tcf of natural gas. The EIA estimates that over the next 25 years, total domestic energy consumption will increase by over 8%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas

120

---

Table of Contents

vehicles. The following charts show the allocation of natural gas usage by end user as well as the relative position of natural gas as a power generation fuel source as of 2010.

Source: EIA, Annual Energy Outlook 2012 (June 2012).

        According to the EIA, as shown in the chart below, during the period from 2001 through 2010, natural gas consumption increased by 9.4% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 66.6 Bcf/d in 2011. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation and commercial/residential sectors, where consumption grew by approximately 42.3% and 1.3%, respectively. The growth in these sectors was partially offset by an approximate 8.1% decline in natural gas consumption in the less seasonal industrial sector.

U.S. Annual & Average Daily Natural Gas Consumption

Source: EIA, U.S. Natural Gas Consumption by End Use (July 2012).

        Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased

121

---

Table of Contents

likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 24.1 Tcf in 2010 to 26.6 Tcf in 2035.

Natural Gas Supply

        Domestic natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 32.4% in 2010. According to EIA data, during the three-year period from January 2007 through December 2010 domestic production of natural gas increased by an average of approximately 3.8% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

        In 2012, the EIA estimated that the United States held 482 Tcf of technically recoverable shale gas resource. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 49% in 2035 as compared with 23% in 2010.

122

---

Table of Contents

Natural Gas Production by Source, 1990-2035

Source: EIA, Annual Energy Outlook 2012 (June 2012).

123

---

Table of Contents

BUSINESS

Overview

        We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of June 30, 2012, our gathering systems had approximately 385 miles of pipeline and 147,600 horsepower of compression. During the first half of 2012, our systems gathered an average of approximately 909 MMcf/d of natural gas, of which approximately 64% contained NGLs that were extracted by a third party processor. We believe that we are positioned to grow through the increased utilization and further development of our existing assets. In addition, we intend to grow our business through strategic partnerships with large producers to provide midstream services for their upstream development projects, as well as through acquisitions in our existing areas of operation and in new areas.

        We generate a substantial majority of our revenue under long-term fee-based, natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

        Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments, or MVCs. Our AMIs cover approximately 330,000 acres in the aggregate, have original terms that range from 10 years to 25 years, and provide that any production from natural gas wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.5 Tcf at June 30, 2012 and, through 2020, average approximately 639 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of June 30, 2012, had a weighted average remaining life of 11.4 years assuming minimum throughput volume for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

        We were formed in 2009 by members of our management team and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. We are currently owned by Energy Capital Partners, GE Energy Financial Services, a global investor in essential, long-lived and capital intensive energy assets with over $20 billion in energy investments worldwide, and certain members of our management team.

        For the six months ended June 30, 2012, we generated $75.9 million of revenue, $16.7 million of net income and $51.5 million of Adjusted EBITDA. For the year ended December 31, 2011, we generated $103.6 million of revenue, $38.0 million of net income and $56.8 million of Adjusted EBITDA. These amounts reflect only two months of operations from our Grand River system, which we acquired in October 2011. Please read "—Our Assets—Grand River System." For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

124

---

Table of Contents

        Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are summarized below.

Grand River System

        In October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin of western Colorado, which we refer to as the Grand River system, from Encana for $590.2 million. The Grand River system comprises approximately 276 miles of pipeline and 97,500 horsepower of compression and is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado. All of the natural gas gathered on the Grand River system is discharged to Enterprise Products Partners L.P.'s pipeline serving its 1.7 Bcf/d processing facility located in Meeker, Colorado. For the six months ended June 30, 2012, the Grand River system gathered an average of approximately 584 MMcf/d from five producers, including Encana as the anchor customer.

        The Grand River system primarily gathers natural gas produced by our customers from the liquids-rich Mesaverde formation within the Piceance Basin. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling activities for several decades. The Grand River system also gathers natural gas produced from our customers' wells targeting the deeper Mancos and Niobrara Shale formations, which have higher initial production rates and lower Btu gas content than Mesaverde wells. Over the last two years, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara Shale formations. Based on our customers' current drilling expectations, we anticipate the majority of our near-term throughput on the Grand River system will continue to be comprised of Mesaverde formation production.

        We intend to expand the Grand River system by connecting additional pad sites within our AMIs, adding new customers and acquiring nearby gathering systems. We expect that, to the extent natural gas prices increase from current levels, our customers will accelerate drilling activities targeting the Mancos and Niobrara shale formations, which will provide us with an opportunity to construct a new medium pressure pipeline system to gather the resulting production and increase throughput on the Grand River system.

DFW Midstream System

        In September 2009, we acquired approximately 17 miles of pipeline and 2,500 horsepower of electric-drive compression in north-central Texas, which we refer to as the DFW Midstream system, from Energy Future Holdings and Chesapeake. Since the initial acquisition, we have expanded the DFW Midstream system by adding approximately 92 miles of pipeline to connect 62 of 73 currently identified pad sites and installing an incremental 47,600 horsepower of compression. The DFW Midstream system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers, directly or indirectly, with the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana. For the six months ended June 30, 2012, the DFW Midstream system gathered an average of approximately 325 MMcf/d from seven producers.

        Our DFW Midstream system benefits from its location within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale formation. This area is commonly referred to as the core of the Barnett Shale and, according to production data sourced from the Texas Railroad Commission, contains the most prolific wells, including the two largest and four of the top ten largest wells drilled to date in the Barnett Shale, based on peak month daily average production rates. Construction of the DFW Midstream system is substantially complete and enables our customers to efficiently produce natural gas by utilizing horizontal drilling techniques throughout the vast majority of our AMIs from pad sites already

125

---

Table of Contents

connected, or identified to be connected, to the DFW Midstream system. Given the urban nature of our area of operations, in what we consider to be the "core of the core" of the Barnett Shale, we expect that the majority of future natural gas drilling in this area will occur from these existing identified pad sites, which should enable us to increase throughput and cash flows with minimal additional capital expenditures.

Business Strategies

        Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:

•

Increasing capacity of and throughput volumes on our existing systems.  We intend to continue to focus on maximizing the utilization of our assets by increasing volume throughput from existing customers and connecting new customers to our systems. The DFW Midstream system is designed to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the DFW Midstream system and do not require significant additional capital expenditures. In addition, we seek to optimize our existing systems by adding third-party volumes that in general would not otherwise be pursued by large upstream producers who are primarily focused on gathering their own production volumes.



•

Capitalizing on organic growth opportunities.  Our existing gathering systems provide us with significant organic expansion opportunities. We intend to leverage our management team's expertise in constructing, developing and optimizing midstream infrastructure assets to grow our business through organic development projects that are designed to extend our geographic reach, diversify our customer base, increase the number of our natural gas receipt points and maximize volume throughput. Our expansion of the DFW Midstream system is expected to increase the system to approximately 120 miles of 8 inch to 30 inch pipeline and 56,100 horsepower of compression. This expansion includes installing additional electric-drive compression that we expect will increase throughput capacity on the DFW Midstream system from 410 MMcf/d to over 450 MMcf/d. We expect that this incremental throughput capacity will be utilized by our existing customers who we expect to drill on previously connected pad sites and new pad sites that we will connect to our system. We expect pad site connections to increase from 62 as of June 2012 to 73 by the end of 2013. Additional projects that we have commenced during 2012 include:



•

Connecting five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.



•

Continuing the construction of a new medium-pressure gathering system alongside portions of our existing low-pressure system in the Piceance Basin. In connection with our acquisition of the Grand River system, we entered into a contractual arrangement with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.



•

Pursuing new customers currently operating in close proximity to our existing gathering infrastructure in the Barnett Shale and the Piceance Basin in order to maximize system capacity utilization. We have successfully pursued this strategy since acquiring the DFW Midstream system in 2009 and it is highlighted by our addition of EOG, Vantage Energy and Beacon E&P as new customers in 2009, 2010 and 2012, respectively. We will continue to pursue this strategy in the Barnett Shale and the Piceance Basin and are currently in discussions with multiple producers to expand our asset footprint and increase our natural gas receipt points.



•

Maintaining our focus on fee-based revenue with minimal direct commodity price exposure.  As we expand our business, we intend to maintain our focus on providing midstream energy services

126

---

Table of Contents

under fee-based arrangements. Our midstream services are almost exclusively provided under long-term, fee-based contracts with original terms ranging from 10 years to 25 years. We do not take title to the natural gas that we gather for our customers and, as a result, our business is not directly exposed to commodity price fluctuations. In addition, we have secured AMIs from certain of our customers covering all of their natural gas production from approximately 230,000 acres in the Piceance Basin and 100,000 acres in the Barnett Shale. We believe that our focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows and increasing our quarterly distributions over time.

•

Partnering with large natural gas producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We pursue opportunities to partner with established producers in unconventional resource basins to develop new infrastructure that we believe will complement our existing midstream assets or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of a strategic acreage position in an unconventional resource play and represent assets that are well-positioned for accelerated production growth but have minimal existing midstream energy infrastructure to support such growth. We have been successful with this strategy and will continue to pursue similar opportunities that utilize our management team's experience in constructing, developing and operating large scale midstream infrastructure. We seek to promote commercial relationships with established producers, such as Encana on the Grand River system and Chesapeake on the DFW Midstream system, who are willing to serve as an anchor customer and are willing to commit to long-term volume and AMIs.



•

Diversifying our asset base by exploring acquisition and development opportunities in various geographical areas and other sectors of the midstream industry. While our natural gas gathering operations in the Piceance Basin and the Barnett Shale currently represent our core business, we intend to diversify our business into other sectors of the midstream industry such as crude oil gathering, storage and transportation, through both greenfield development projects and acquisitions, and into other geographic regions. We and our sponsors are frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energy infrastructure assets. Working together with our sponsors, we intend to continue to evaluate opportunities to acquire or develop other midstream energy infrastructure assets that complement our existing business and allow us to leverage our asset base and our management team's development and industry expertise.

Competitive Strengths

        We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:

•

Strategically located assets in core areas of prolific unconventional basins supported by existing partnerships with large producers to provide midstream services for their development projects.  Our midstream energy infrastructure assets are strategically positioned within the core areas of two established unconventional resource plays. The formations in the basins served by our assets have relatively low drilling and completion costs. We believe that producers will continue their drilling and completion activities in the core areas of unconventional natural gas shale basins even if natural gas prices do not increase significantly from current levels because the return economics associated with core-area wells remain favorable in lower pricing environments compared to more marginal areas of production. We believe that continued drilling activity in these basins positions us to pursue attractive growth opportunities by further developing and optimizing our systems and by developing or acquiring complementary systems within our geographic areas of operation.

127

---

Table of Contents

•

Grand River system. The Grand River system is located in the Piceance Basin and currently serves the established liquids-rich Mesaverde formation and is optimally located for expansion to serve the emerging Mancos and Niobrara Shale formations. In the Piceance Basin, production from the emerging Mancos and Niobrara Shale formations has only recently begun, as producers have started drilling wells in these formations in the last two years. We have begun constructing portions of a new medium-pressure gathering system to service anticipated future higher pressure gas production from the emerging Mancos and Niobrara Shale formations.



•

DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, Texas, currently the largest natural gas producing county in the state. We consider this area to be the "core of the core" of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. We believe that the AMIs underpinning our system are substantially undeveloped compared to other areas in the Barnett Shale due to the lack of historical gathering infrastructure in this area and limited associated drilling activity. We believe that our AMIs and our system footprint provide us with a competitive advantage to add additional producers and incremental volumes in this growing area of the Barnett Shale at a competitive capital cost.



•

Fee-based revenues underpinned by long-term contracts.  A substantial majority of our revenue for the year ended December 31, 2011 and the six months ended June 30, 2012 was generated under long-term, fee-based gas gathering agreements. Several of our customers are among the largest producers in each of our areas of operation. In the Piceance Basin, we have a 25-year AMI covering approximately 187,000 acres and a 15-year minimum volume commitment with Encana for approximately 1.5 Tcf. Together with our other gas gathering agreements with producers in the Piceance Basin, we have AMIs covering approximately 230,000 acres, average minimum volume commitments of 501 MMcf/d through 2020 and total volume commitments of almost 2.1 Tcf in the Piceance Basin through 2026. Our gas gathering agreements with our Barnett Shale customers have AMIs covering approximately 100,000 acres in the high-growth core area of the Barnett Shale and minimum volume commitments of approximately 429 Bcf through 2020. We believe that having long-term, fee based gas gathering agreements with minimal direct commodity price exposure enhances the predictability of our performance.



•

Capital structure and financial flexibility.  At the closing of this offering, we expect to have approximately $     million of borrowing capacity available to us under our amended and restated revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital will provide us with the requisite financial flexibility to execute our growth and expansion strategy.



•

Experienced management team with proven record of asset acquisition, construction, development, operation and integration expertise.  Our executive management team has an average of 16 years of energy experience and a proven track record of identifying and consummating significant acquisitions in addition to partnering with major producers to construct and develop midstream infrastructure. As demonstrated by our current business, our management team has demonstrated particular expertise in constructing new—and developing and optimizing underutilized—midstream assets, which are key elements of our growth strategy. We employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream energy projects.



•

Relationships with large and committed financial sponsors.  Our sponsors, Energy Capital Partners and GE Energy Financial Services, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality midstream energy assets. Energy Capital Partners has indicated that it intends to use us as its primary platform for the acquisition, construction and development of future midstream infrastructure assets; however, it

128

---

Table of Contents

is not obligated to do so. While there are no assurances that we will benefit from our relationship with our sponsors, we believe our relationship with both of our sponsors will be a competitive advantage, as they both bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will benefit us as we seek to grow our business. In addition, we believe that Energy Capital Partners and GE Energy Financial Services, as the indirect owners of our general partner interest, all of our incentive distribution rights and a        % limited partner interest in us, will be motivated to promote and support the successful execution of our business strategies.

Our Sponsors

        We were formed in 2009 by members of our management and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us. To date, Energy Capital Partners and its affiliated funds have 22 investment platforms with investments in the power generation, electric transmission, midstream natural gas and renewable sectors of the energy industry. In August 2011, Energy Capital Partners sold an interest in Summit Investments to GE Energy Financial Services. GE Energy Financial Services invests globally in essential, long-lived and capital-intensive energy assets. To date, GE Energy Financial Services has invested over $20 billion in energy investments worldwide, of which approximately $2.4 billion has been committed to midstream-related portfolio companies.

Our Assets

        Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are discussed in more detail below.

Grand River System

        The following table provides information regarding our Grand River system as of June 30, 2012, unless otherwise noted.

129

---

Table of Contents

        In October 2011, we acquired the Grand River system from Encana for $590.2 million. The Grand River system is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado, and comprises approximately 276 miles of 3 inch to 24 inch diameter pipeline and approximately 97,500 horsepower of compression. The Grand River system gathers natural gas from the Mesaverde, Mancos and Niobrara Shale formations located within the Piceance Basin. All of the natural gas volumes gathered on the Grand River system are discharged to third-party pipelines that deliver to Enterprise Products Partners L.P.'s 1.7 Bcf/d processing facility located in Meeker, Colorado.

        The Grand River system has total throughput capacity of 885 MMcf/d and for the six months ended June 30, 2012 gathered an average of approximately 584 MMcf/d. The system gathers production from the Mamm Creek, South Parachute and Orchard fields in the area around Rifle, Colorado. The Grand River system is underpinned by long-term, fee-based gas gathering agreements with Encana, WPX Energy, Bill Barrett Corporation and Antero Resources that include minimum volume commitments with original terms ranging from 10 to 15 years and AMIs with original terms ranging from 10 years to 25 years. As of June 30, 2012, these gas gathering agreements had remaining minimum volume commitments totaling approximately 2.1 Tcf over the next 15 years, an average of approximately 501 MMcf/d through 2020, and AMIs covering approximately 230,000 acres for terms of up to 25 years. Our customers do not have leases that currently cover our entire AMIs in the Piceance Basin but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the Grand River system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

        The Grand River system is currently a low-pressure gathering system that was originally designed to gather natural gas produced from traditional vertical wells focused on the shallower, higher-Btu Mesaverde formation. Our largest Grand River customer, Encana, currently has approximately 1,736 wells on approximately 376 pad sites connected to our existing low-pressure gathering system. We also receive natural gas from other producer customers at nine central receipt points on the Grand

130

---

Table of Contents

River system. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize the existing available throughput capacity.

        In connection with our acquisition of the Grand River system, we entered into a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

DFW Midstream System

        The following table provides information regarding our DFW Midstream system as of June 30, 2012, unless otherwise noted.

        The DFW Midstream system is located within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale geologic formation. We consider this area to be the "core of the core" of the Barnett, which, according to production data sourced from the Texas Railroad Commission, contains the most prolific wells, including the two largest and four of the ten largest wells drilled to date in the Barnett Shale, based on peak month daily average production rates. The DFW Midstream system, which has been under

131

---

Table of Contents

construction since 2008, includes gathering lines ranging from 8 inches to 30 inches in diameter and is located along existing electric transmission corridors and under both private and municipal property. The system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers with the major natural gas market hubs of Waha, Carthage and Katy in Texas and Perryville and Henry Hub in Louisiana.

        Our development of the DFW Midstream system is underpinned by eight long-term, fee-based gas gathering agreements with Chesapeake, TOTAL, Carrizo, Beacon E&P, Atlas Energy, EOG, Exxon Mobil and Vantage. As of June 30, 2012, these gas gathering agreements have remaining minimum volume commitments totaling approximately 429 Bcf and, through 2020, average approximately 138 MMcf/d. In addition, these gas gathering agreements have AMIs that cover approximately 100,000 acres through 2030. Our customers do not have leases that currently cover our entire AMIs in the Barnett Shale but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the DFW Midstream system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

        We have owned and operated the DFW Midstream system since 2009, when we acquired it from Energy Future Holdings and concurrently acquired certain complimentary pipeline and other related gathering system assets from Chesapeake. We simultaneously entered into a long-term gas gathering agreement with Chesapeake as our anchor customer that included a 20-year AMI covering approximately 95,000 acres and a 10-year minimum volume commitment totaling approximately 450 Bcf. At the time of the acquisition, the DFW Midstream system had average throughput of approximately 10 MMcf/d and had approximately 17 miles of pipeline and 2,500 horsepower of installed electric-drive compression in service.

        Since the acquisition, we have expanded the DFW Midstream system by adding approximately 92 miles of additional pipeline and 47,600 horsepower of compression. For the six months ended June 30, 2012, the DFW Midstream system had average throughput of approximately 325 MMcf/d. We continue to develop the DFW Midstream system to extend our gathering reach, diversify our customer base, increase our receipt points and maximize throughput on the system. In 2012, we intend to continue to connect additional pad sites located within our AMIs and expand the throughput capacity from 410 MMcf/d to over 450 MMcf/d by installing additional electric-drive compression. The system will include approximately 120 miles of low- and high-pressure gathering lines and 56,100 horsepower of compression. As of June 30, 2012, approximately 311 wells on 62 pad sites were connected to the DFW Midstream system and 32 additional wells were in various stages of completion, 27 of which are on existing pad sites that we currently serve and 5 of which are on pad sites to which we intend to connect.

        While there has been substantial development of the broader 24-county Barnett Shale over the past decade, southeastern Tarrant County, which is located in the core area of the Barnett Shale, has been largely undeveloped due to the urban landscape and the absence of natural gas gathering infrastructure. The DFW Midstream system, which is primarily located in southeast Tarrant County, has addressed the historical lack of gathering infrastructure and currently provides producers in the area with a safe, efficient and reliable solution to deliver their natural gas to market. Tarrant County, which is currently the largest natural gas producing county in Texas, experienced an increase in natural gas production from 1.6 Bcf/d in October 2009 to 2.2 Bcf/d in May 2012. Over this same period, throughput on the DFW Midstream system increased from approximately 10 MMcf/d to approximately 350 MMcf/d, which accounted for approximately 60% of Tarrant County's increased natural gas production.

        We believe the production profile of wells drilled within our AMIs, which includes the two largest wells ever drilled in the Barnett Shale, will continue to attract drilling activity over the long term as producers become more selective in their drilling locations in order to maximize their returns. We also

132

---

Table of Contents

believe that the acreage dedicated to the DFW Midstream system is substantially undeveloped as evidenced by our 100,000 acre gathering footprint and our customers' desire to reduce well spacing below 50 acres to maximize recoverable reserves. We believe our strategic location in the core of the core of the Barnett Shale provides us with a competitive advantage to add incremental throughput with limited additional investment capital due to the anticipated future, high-density, infill drilling from our customers on connected pad sites and nearby pad sites that have yet to be connected. This high-density, infill drilling, is magnified in our area given the urban landscape and the desire of our producer customers to minimize their surface footprint.

Gas Gathering Agreements

        We derive revenue primarily from long-term, fee-based, gas gathering agreements, or GGAs, with some of the largest and most active producers in our areas of operation. The following describes the material provisions included in the majority of our firm gas gathering agreements with our significant customers, including our natural gas gathering agreements with Chesapeake, Encana, Carrizo Oil and Gas and WPX Energy.

AMIs and Contract Terms

        Our gas gathering agreements contain AMIs. The AMIs generally have original terms that range from 10 years to 25 years and require that any production by our customers within the AMIs will be shipped on gathering systems. Under certain of our GGAs, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. If we choose to forego a discretionary opportunity presented by the customer, such as constructing a lateral to an additional pad site, or constructing additional pipeline infrastructure or related assets in connection with a customer's expansion of its drilling operations, the customer may, in certain circumstances, construct the additional infrastructure and sell it to us at a price equal to their cost plus an applicable margin, or, in some cases, release the relevant acreage dedication from the AMI.

Minimum Volume Commitments

        Our gas gathering agreements contain minimum volume commitments, or MVCs, pursuant to which our customers guarantee to ship a minimum volume of natural gas on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. The original terms of the MVCs range from 7 to 15 years. In addition, certain of our customers have an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.

        If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas

133

---

Table of Contents

gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable).

•

To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped volumes in excess of its MVCs. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.



•

To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall payment owed in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular GGA.

Fuel Retainage Fees and Cost Pass-Throughs

        Our GGAs on our DFW Midstream system allow us to retain a small fixed percentage of the natural gas that we receive at the receipt points to offset the costs we incur to operate our electric-drive compressors. On average, we retain nominal amounts of the natural gas received at the receipt points on the DFW Midstream system. Our GGAs on our Grand River system allow us to (i) charge our customers for the electricity costs we incur to operate our electric-drive compressors and (ii) utilize physical gas on the Grand River system to operate our gas-fired compressors.

Pressure Variance Penalties

        Our GGAs require us to maintain certain specified operating pressures on our gathering systems, both on a system-wide basis and with respect to each receipt point. We are also required to maintain certain minimum operating pressures at certain of our compressor stations. If we fail to maintain our required system and receipt point operating pressures, we can be subject to penalties in the form of substantial reductions in our gathering fees (subject, in certain circumstances, to force majeure relief). These reductions generally range from 25% to 75%, depending on the duration of the pressure variance. With respect to compressor station pressure variances, we are subject to penalties in the form of loss of our fuel retainage fees and our ability to pass our electricity costs on to the customer for a period of time, depending on the duration of the pressure variance. With respect to system and receipt point pressure variances that persist for extended periods of time (generally exceeding four months in any consecutive twelve month period), our customers are entitled to additional remedies, including:

•

a 100% reduction in gathering fees applicable to future shipments until the end of the first month following the resolution of the pressure variance; and



•

the ability to release all or a portion of the customer's future gas production from the GGA.

Future Development GGA

        In connection with our acquisition of the Grand River System, we agreed to invest capital, subject to a maximum of $200 million in any annual period, to construct the necessary facilities to support Encana's drilling program in the Mancos and Niobrara shale formations. Instead of an MVC, this future development agreement contains a reimbursement mechanism under which Encana guarantees repayment of our capital expenditures within five years of investment. Encana's guarantee is partially offset by certain revenues that we may receive in respect of the new gathering facilities.

134

---

Table of Contents

Competition

        The natural gas gathering, compression and transportation business is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to end-use markets, location, available capacity, capital expenditures and fuel efficiencies. Our principal competitors in the Fort Worth Basin are Access Midstream Partners, L.P., Crestwood Midstream Partners LP and Energy Transfer Partners, L.P. Our principal competitors in the Piceance Basin are Williams Partners L.P., Energy Transfer Partners, L.P. and Enterprise Products Partners L.P.

        In the future, we may face competition for production drilled outside of our AMIs and on attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition.

Safety and Maintenance

        We are subject to regulation by DOT under the Natural Gas Pipeline Safety Act of 1968, as amended, also known as the NGPSA, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas pipeline facilities. In the Pipeline Safety Act of 1992, also known as the PSA, Congress expanded DOT's regulatory authority to include "regulated gathering lines" that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002, also known as the PSIA, and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, also known as the PIPES Act, established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.

        DOT has delegated the implementation of safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations, similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW gathering system is located, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

135

---

Table of Contents

        While repairs, remediation or preventative or mitigation measures resulting from integrity management inspections could obligate us to make material expenditures, we do not anticipate such an outcome because our pipelines are relatively new.

        Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and extend the integrity management requirements to certain gathering lines. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

        We believe that we are in compliance with existing safety laws and regulations and we cannot predict the outcome of new regulatory initiatives; however, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues.

        We are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act, or the OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to the OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We are also subject to EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety, community right to know laws, and the security of our facilities.

Regulation of the Oil and Natural Gas Industries

General

        Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at uncontrolled market prices; however, regulation of gathering and transportation services may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services. FERC and FTC are also authorized to prevent and sanction market manipulation in natural gas markets and petroleum markets, respectively. State and municipal regulations may apply to the production and gathering of natural gas, the construction and operation of natural gas and crude oil facilities, and the rates and practices of gathering systems and intrastate pipelines.

136

---

Table of Contents

Regulation of Oil and Natural Gas Exploration, Production and Sales

        Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.

        Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of resources, including provisions for the unitization or pooling of producing properties, the establishment of maximum rates of production from wells, and the regulation of spacing of wells. These state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering by us.

Regulation of the Gathering and Transportation of Natural Gas

        We believe that our gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA, although we are subject to FERC's anti-market manipulation regulations. Please read "—Anti-Market Manipulation Rules" below. The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

        Our gathering of natural gas is also affected by the availability, terms and cost of downstream transportation services. The rates and terms for access to pipeline transportation services are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing systems have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. FERC's regulations require, among other things, that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of FERC's initiatives has been to eliminate the interstate pipelines' traditional role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a non-discriminatory basis. The rates for such transportation and storage services are subject to FERC ratemaking authority, and FERC exercises its authority by applying cost-of-service principles, allowing for the negotiation of rates where there is a cost-based alternative rate or granting market-based rates in certain circumstances, typically with respect to storage services.

137

---

Table of Contents

        Natural gas production, gathering and transportation may be subject to state and local regulations that may change from time to time. Our construction of new gathering facilities and expansion of existing gathering facilities may be subject to state and local regulation, including approval and permit requirements. Regulation of our operations may cause us to incur additional operating costs or limit the quantities of gas we may gather. In addition, state ratable take statutes and regulations generally require us to take natural gas production that may be tendered to us for handling without undue discrimination. These statutes are designed to prohibit discrimination in favor of one source of supply over another source of supply and they restrict our right to decide whose production we gather.

        Gathering systems and pipelines may be subject to regulation by state regulatory authorities with respect to safety (under a federal certification) and rates and practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we have filed a tariff with the Texas Railroad Commission to establish rates and terms of service for our DFW operations. We have not been required to file a tariff in Colorado for our Grand River assets. Both of these states have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint.

        Intrastate pipelines that provide interstate transportation service are regulated by FERC under Section 311 of the NGPA as to rates and other terms and conditions of service with respect to interstate gas shipments, unless an exemption from such regulation applies (such as for gathering lines). We believe that our pipelines are gathering systems that are therefore exempt from Section 311 requirements.

        Changes in federal, state, or local law or policy may affect us either directly or indirectly. While we cannot predict what further action legislators or regulators will take, we do not believe that any such action taken will affect us differently, in any material way, than other midstream companies with which we compete.

Regulation of Crude Oil and NGL Transportation Rates

        In a number of instances the ability to transport and sell crude oil and NGLs is dependent on pipelines whose rates and other terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992, state regulatory jurisdiction under state statutes, or both. Interstate transportation rates for crude oil and NGLs, among other liquid commodities, are regulated by FERC, and, in general, these rates must be cost-based or based on rates in effect in 1992, although FERC has established an indexing system for such transportation rates which allows pipelines to take an annual inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. FERC has also established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances.

        In other instances involving intrastate-only transportation of crude oil, NGLs and other products, the ability to transport and sell such commodities is dependent on transportation by pipelines at rates, and on other terms and conditions of service that are subject to regulation by state regulatory authorities. Such pipelines may be subject to state regulation with respect to safety (under a federal certification) and rates and other practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of intrastate liquids pipelines varies from state to state. Many states operate on a complaint-based system and state authorities have generally not initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.

138

---

Table of Contents

Anti-Market Manipulation Rules

        We are subject to the anti-market manipulation provisions in the NGA, as amended by EPAct 2005, which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, FTC holds statutory authority under the EISA to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to one million dollars ($1,000,000) per day per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Failure to comply with such market rules, regulations and requirements could have a material adverse effect on our business, results of operations, and financial condition.

Environmental Matters

General

        Our operation of pipelines and other facilities for the gathering, compressing and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•

requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;



•

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;



•

delaying system modification or upgrades during permit reviews;



•

requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and



•

enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

        Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws

139

---

Table of Contents

and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

        We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

        Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

        We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

        We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

140

---

Table of Contents

Oil Pollution Act (OPA)

        In 1991, the EPA adopted regulations under the OPA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan, or SPCC, for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

        Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

        Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA must finalize the proposed amendments by December 14, 2012. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. Compliance with the final rule currently is required by October 2013. We are continuing our evaluation of the cost impacts of the final rule and proposed amendments.

        On June 28, 2011, the EPA issued a final rule, effective August 29, 2011 modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule is not required until at least 2013. On May 22, 2012, the EPA proposed minor amendments which must

141

---

Table of Contents

be finalized by December 14, 2012. We are currently evaluating the impact that this final rule and proposed amendments will have on our operations.

        On April 17, 2012, the EPA finalized rules that establish new air emission control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or 60 days after the final rule is published in the Federal Register. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, the EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, which may impact our customers. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. These requirements may result in increased operating costs for producers who drill near our pipelines, which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Business—Environmental Matters—Hydraulic Fracturing."

        These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unit holders.

Water Discharges

        The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

142

---

Table of Contents

Hydraulic Fracturing

        The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities, and we believe that our facilities will not be materially adversely affected by such requirements. However, a portion of our customers' natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process. Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between the latter part of 2012 and 2014. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities. On May 4, 2012, the BLM issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.

        Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. We cannot predict whether any other legislation will be enacted in the future and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Risk Factors—Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues."

Endangered Species

        The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas.

143

---

Table of Contents

National Environmental Policy Act

        The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

        Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent by 2020 compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

        In the United States, legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a "cap and trade" program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an "air pollutant," and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act.

        In addition, in September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. We are required to report under these rules for certain of our assets. The EPA continues to consider additional climate change requirements, such as the March 2011 proposed rules regarding future coal-fired power plants. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. However, due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact that related developments will have on us.

        Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

144

---

Table of Contents

        The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Anti-terrorism Measures

        The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

Title to Properties and Rights-of-Way

        Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to perpetual easements between us and the underlying fee owner, or permits with governmental authorities. Our Predecessor leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the exception of certain permits with governmental entities that have been applied for, but not yet issued.

Employees

        We do not have any employees. The officers of our general partner will manage our operations and activities. As of June 30, 2012, Summit Midstream Partners, LLC employed 89 people who provide direct, full-time support to our operations, including 19 field-level employees we hired from Encana in connection with our acquisition of the Grand River system. Subsequent to the closing of this offering, all of the employees required to conduct and support our operations will be employed by our general partner or its affiliates. None of these employees are covered by collective bargaining agreements, and our general partner considers its employee relations to be good.

Legal Proceedings

        Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

145

---

Table of Contents

MANAGEMENT

Management of Summit Midstream Partners, LP

        We are managed by the directors and executive officers of our general partner, Summit Midstream GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Summit Investments, which is controlled by Energy Capital Partners and GE Energy Financial Services, is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. All decisions of the board of directors of our general partner will require the affirmative vote of a majority of all of the directors constituting the board, provided that such majority includes at least a majority of the directors designated as an "Energy Capital Partner Designated Director" by Energy Capital Partners. The initial Energy Capital Partner Designated Directors are Thomas K. Lane, Andrew F. Makk and Curtis A. Morgan. Our unitholders are not entitled to directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Director Independence

        Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed limited partnership like us to have, and we do not intend to have, a majority of independent directors on the board of directors of our general partner.

Committees of the Board of Directors

        The board of directors of our general partner will have an audit committee, or the Audit Committee, and a conflicts committee, or the Conflicts Committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

        William J. Glasgow, Andrew F. Makk and Thomas K. Lane will serve as the initial members of the Audit Committee. Mr. Glasgow will serve as the initial chair of our Audit Committee and satisfies the SEC and NYSE rules regarding independence and as the audit committee financial expert. Our general partner will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of the Audit Committee. Those rules permit our general partner to have an audit committee that has one independent member upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. In compliance with those rules, Mr. Lane will resign from the Audit Committee upon appointment of the first such additional independent director and Mr. Makk will resign from the Audit Committee when the final independent director is appointed. Thereafter, our general partner is generally required to have at least three independent directors serving on its board at all times. The Audit Committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee will also be responsible for confirming the independence

146

---

Table of Contents

and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the Audit Committee.

Conflicts Committee

        At the direction of our general partner, our Conflicts Committee will review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The Conflicts Committee will determine if the resolution of the conflict of interest is in the best interests of our partnership. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, employees of any of its affiliates, may not hold any ownership interest in our general partner or us and our subsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Our Conflicts Committee will consist of one or more directors meeting these requirements, and William J. Glasgow will serve as the initial member and chair of our Conflicts Committee. We anticipate that once appointed to our general partner's board of directors, the additional independent members appointed to the Audit Committee will also serve on the Conflicts Committee. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the board of directors of our general partner including any member of the Conflicts Committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been taken or omitted in good faith.

Directors and Executive Officers

        Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

        Steven J. Newby has been the President and Chief Executive Officer of our general partner since May 2012. Mr. Newby was a founding member of Summit Midstream Partners, LLC and has been the President and Chief Executive Officer of Summit Midstream Partners, LLC since its formation in

147

---

Table of Contents

September 2009. Mr. Newby's background includes over 15 years of oil and gas experience with a focus on the midstream sector of the energy industry. Mr. Newby was a founding member of SunTrust Bank's Corporate Energy industry specialty group and ultimately became a Managing Director and Head of the Project Finance Group within SunTrust's Capital Markets division. In 2007, Mr. Newby joined ING Investment Management to manage a $300 million proprietary fund focused on the private and public investment in the energy infrastructure space. Mr. Newby is a graduate of the University of North Carolina at Chapel Hill with a B.S. in Business Administration with a concentration in Finance.

        Matthew S. Harrison has been the Senior Vice President and Chief Financial Officer of our general partner since May 2012. Prior to joining our general partner, Mr. Harrison was the Senior Vice President and Chief Financial Officer of Summit Midstream Partners, LLC since September 2011. Mr. Harrison's background includes over 12 years of energy and finance experience. Mr. Harrison joined Summit Midstream Partners, LLC from Hiland Partners, LP, where he served as Executive Vice President and Chief Financial Officer, Secretary and Director from February 2008 to September 2011. Prior to joining Hiland, Mr. Harrison was a Director in the Energy & Power Merger & Acquisitions group at Wachovia Capital Markets from October 2007 to February 2008 and a Director in the Mergers & Acquisitions group at A.G. Edwards & Sons, Inc. from July 1999 to October 2007. Mr. Harrison is a Certified Public Accountant and was a Senior Accountant for PricewaterhouseCoopers for five years. Mr. Harrison received an MBA from Northwestern University—Kellogg Graduate School of Management in 1999 and a B.S. in Accounting from the University of Tennessee in 1992.

        Brad N. Graves has been the Senior Vice President of Corporate Development of our general partner since May 2012. Prior to joining our general partner, Mr. Graves was the Senior Vice President of Corporate Development of Summit Midstream Partners, LLC since April 2010. He was previously a Partner with Crestwood Midstream Partners, LLC from February 2008 until March 2010. Mr. Graves has served as Executive Vice President—Business Development of Genesis Energy, LP (AMEX: GEL) from August 2006 until November 2007. He also served as Vice President—Offshore Commercial for Enterprise Products Partners L.P. (NYSE: EPD) from 2004 until August 2006. Prior to 2004, Mr. Graves served in a variety of commercial roles at EPD and GulfTerra Energy Partners, LP (NYSE: GTM), prior to its merger with EPD. In his roles with EPD and GTM, Mr. Graves participated in numerous greenfield projects developed in the Gulf of Mexico. Mr. Graves earned a B.B.A. in Accounting from Texas A&M University in 1989 and an MBA in Marketing and Finance from the University of Saint Thomas in 1994.

        Rene L. Casadaban has been the Senior Vice President of Engineering, Construction, and Operations of our general partner since May 2012. Prior to joining our general partner, Mr. Casadaban was the Senior Vice President of Engineering, Construction and Operations of Summit Midstream Partners, LLC from February 2011 until April 2012, and prior to that he served as a vice president from the time he joined Summit Midstream Partners, LLC in November 2010. Mr. Casadaban has 20 years of project management experience for onshore, offshore and deepwater pipeline systems. Prior to joining Summit Midstream Partners, LLC, Mr. Casadaban worked for Enterprise Products Partners L.P. from 2006 to 2010 as the Director for Deepwater Development of floating production platforms and offshore pipelines. Mr. Casadaban has also served as an independent consultant to ExxonMobil and GulfTerra for Gulf of Mexico and international pipeline projects. At Land & Marine, Mr. Casadaban was responsible for managing domestic and international pipeline river crossings and beach approaches by horizontal directional drilling. Mr. Casadaban is a graduate of Auburn University with a B.S. in Building Construction.

        Brock M. Degeyter has been the Senior Vice President and General Counsel of our general partner since May 2012. Mr. Degeyter joined Summit Midstream Partners, LLC in January 2012 as Senior Vice President and General Counsel. Mr. Degeyter's background includes over ten years of energy, finance and business law experience. Prior to joining our general partner, Mr. Degeyter worked in the

148

---

Table of Contents

corporate legal department for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director of Corporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with the firm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed to practice law in the states of Texas and Louisiana. Mr. Degeyter received a B.A. in Political Science from Louisiana State University and a J.D. from Loyola University College of Law in New Orleans.

        Thomas K. Lane has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Lane has been a partner of Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton College and an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

        Andrew F. Makk has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Makk has been a Principal at Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, he was a co-founder of a privately held energy company from 2002 to 2005, which built a portfolio of energy projects in Europe on behalf of a private equity fund. Prior to 2002, Mr. Makk spent nine years with Enron International in various power and LNG asset development roles and became Head of Asset Development for Enron Europe in London. He received a B.S.M. in Finance from Tulane University and an MBA from the Fuqua School of Business at Duke University. Mr. Makk was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

        Curtis A. Morgan has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Morgan has served as the President and Chief Executive Officer of EquiPower Resources Corp. since May 2010. Prior to joining EquiPower Resources Corp., he served as an Operating Partner of Energy Capital Partners from May 2009 to May 2010. Prior to joining Energy Capital Partners, he served as President and Chief Executive Officer of FirstLight Power Enterprises from November 2006 to April 2009. Mr. Morgan has also held leadership positions at NRG Energy, Mirant Corporation and Reliant Energy. Mr. Morgan received a B.A. in Accounting from Western Illinois University and an MBA in Finance and Economics from the University of Chicago. He is a Certified Public Accountant. We believe that Mr. Morgan's extensive executive, financial and operational experience bring important and necessary skills to the board of directors.

        William J. Glasgow has served as a director of our general partner since August 2012. Additionally, Mr. Glasgow serves as the chair of the Conflicts Committee of our general partner and serves as the chair and financial expert of the Audit Committee of our general partner. Mr. Glasgow served as the Chief Restructuring Officer of AIG Global Real Estate Investment Corp., an international real estate investment branch of American International Group, Inc. (AIG), from August 2009 until August 2012. Prior to joining AIG, he held several leadership positions, including Chief Operating Officer, at Scanlan Kemper Bard Companies LLC, a real estate private equity firm, from March 2007 to July 2009. Previously, Mr. Glasgow held various senior positions at PacifiCorp, including Chief Financial Officer. He also served as Chairman, President and CEO of PacifiCorp Holdings, Inc., which included PacifiCorp Financial Services, Inc., Nerco, Inc. and Pacific Telecom, Inc. His career also includes leadership positions in venture capital management, including BCN Data Systems, LLC, an

149

---

Table of Contents

international joint venture controlled by Bechtel Enterprises. Mr. Glasgow received a B.S. degree in Economics, magna cum laude, from the Wharton School of Business at the University of Pennsylvania and a J.D. degree, magna cum laude, from Harvard Law School. We believe that Mr. Glasgow's extensive experience as a chief financial officer, senior executive and lawyer in various industries, including the energy and utility sectors, brings substantial leadership skills and experience to the board of directors.

Director Compensation

        Our general partner did not have any independent directors in 2011. As described above under "Committees of the Board of Directors—Audit Committee", our general partner will eventually have at least three independent directors. The independent directors and Mr. Morgan will receive a $50,000 annual retainer and $50,000 in annual unit compensation. The chairman of the Audit Committee will receive an additional annual retainer of $15,000; the chairman of each other committee will receive an additional annual retainer of $7,500; and each independent member of any committee (other than the chairman) will receive an additional annual retainer of $1,500. None of the employee directors have been or will be compensated for their services as directors.

Executive Compensation

        The following describes the material components of our compensation policies with respect to the following individuals, who are our general partner's executive officers and referred to as the "named executive officers":

•

Steven J. Newby, President and Chief Executive Officer;



•

Matthew S. Harrison, Senior Vice President and Chief Financial Officer; and



•

Rene L. Casadaban, Senior Vice President, Engineering, Construction and Operations.

Summary Compensation Table for 2011

        The following table sets forth certain information with respect to the compensation paid to our named executive officers for the year ended December 31, 2011.

150

---

Table of Contents

Narrative Disclosure to Summary Compensation Table


Elements of Compensation

        The primary elements of compensation for the named executive officers are base salary, annual incentive compensation and long-term equity-based compensation awards. The named executive officers also receive certain retirement, health, welfare and additional benefits as described below.

        Base Salary.     Base salaries for our named executive officers have generally been set at levels deemed necessary to attract and retain individuals with superior talent. None of our named executive officers received any base salary adjustments or increases during 2011, other than cost of living increases provided to all of our employees. However, effective March 2012, generally in preparation for this offering, base salary increases were approved for each named executive officer other than Mr. Harrison, whose base salary was set in September 2011 upon his commencement of employment with us. The base salaries of our named executive officers before and after the increase, as applicable, are set forth in the following table:

        Annual Incentive Compensation.     For 2011, Messrs. Newby and Harrison had target bonuses of $223,500 and $221,250, respectively, or 75% of their base salaries. Our board of directors used its discretion to award both executives bonuses slightly in excess of their targets because, although we underperformed on our Adjusted EBITDA targets, we successfully completed our acquisition of the Grand River system under their leadership. Pursuant to Mr. Harrison's employment agreement, his bonus was not prorated, despite his September hire date.

151

---

Table of Contents

        Mr. Casadaban's target incentive compensation was 75% of his base salary, or $150,000. Quantitative factors determined 70% of Mr. Casadaban's incentive compensation and qualitative factors determined 30%. Quantitative factors considered in determining the bonus included achievement of certain Adjusted EBITDA thresholds, construction goals and operational and safety goals. Although we underperformed on our Adjusted EBITDA targets, we achieved near target on our construction goals and significantly above target on our operational goals. As a result, Mr. Casadaban was awarded $79,800 or 76% of target for the portion of his bonus based on quantitative factors, and $75,200 or 167% of target for the portion of his bonus based on qualitative factors, primarily due to his significant contributions to the closing of the acquisition of the Grand River system. In total, Mr. Casadaban was awarded approximately 103% of his target incentive compensation for 2011.

        Long-Term Equity-Based Compensation Awards.     The named executive officers were each granted equity-based compensation awards in the form of interests ("upstairs profits interests") in a collective partnership vehicle, referred to in this prospectus as Summit Management, through which our named executive officers indirectly hold Class B percentage interests in Summit Investments ("downstairs profits interests"). The downstairs profits interests represent indirect interests in Summit Investments' future profits, and allow Summit Management to share in distributions by Summit Investments only after Summit Investments' Class A Members have received distributions in an amount equal to the sum of the fair market value of the downstairs profits interests at the time of grant plus any capital contributions made subsequent to the date of grant. The upstairs profits interests entitle the named executive officers to receive from Summit Management the proceeds of any distributions received by Summit Management from Summit Investments in respect of the corresponding downstairs profits interests, subject to the terms set forth in the partnership agreement of Summit Management. The upstairs profits interests are referred to in this prospectus as the Pre-IPO Equity Awards.

        The Pre-IPO Equity Awards were granted subject to a five-year time-based vesting schedule, subject to the named executive officer's continued employment through the applicable vesting date. The Pre-IPO Equity Awards are eligible for an additional one year of vesting in the event the named executive officer's employment is involuntarily terminated by the applicable employer without cause, or is terminated due to the named executive officer's death or disability, or, in the case of Mr. Newby, is terminated by him due to his resignation with good reason (as defined in the employment agreements, described below). The Pre-IPO Equity Awards are eligible for full 100% accelerated vesting if the named executive officer's employment is involuntarily terminated without cause or, in the case of Mr. Newby, is terminated by the named executive officer due to his resignation with good reason, within the 12 months after a change in control of Summit Investments. In the event of a named executive officer's termination of employment for any other reason, the named executive officer's Pre-IPO Equity Awards will be forfeited.

        Pursuant to the applicable partnership agreements, the vested downstairs profits interests may be repurchased by the applicable employer or Energy Capital Partners in certain circumstances. In the event of the termination of a named executive officer's employment due to death, disability, termination by the applicable employer without cause or, in the case of Mr. Newby, resignation with good reason or non-extension of the term of the employment agreement, the repurchase price will be equal to the value of the downstairs profits interests in a hypothetical liquidation of the applicable employer pursuant to the rights and preferences set forth in the partnership agreement, assuming all assets were sold for their fair market value. In the event of termination for cause, resignation (in the case of Mr. Newby, without good reason) or a purported transfer by the named executive officer or the management company in violation of the partnership agreement, the repurchase price will equal $0. In the event of a repurchase of the downstairs profits interests, the corresponding upstairs profits interests will be repurchased from the named executive officer by Summit Management for the same repurchase price.

152

---

Table of Contents

        Going forward, we expect that equity-based incentive awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process. In anticipation of this offering, we intend to adopt a new long-term equity incentive plan, which is discussed in more detail under "2012 Long-Term Incentive Plan" below.

        Retirement, Health and Welfare and Additional Benefits.     The named executive officers are eligible to participate in such employee benefit plans and programs as we may from time to time offer to our employees, subject to the terms and eligibility requirements of those plans. The named executive officers are eligible to participate in a tax-qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2011, we made a fully vested contribution on behalf of each of the 401(k) plan's participants equal to 3% of such participant's salary for the year.

Outstanding Equity Awards at December 31, 2011

        The following table provides information regarding the Pre-IPO Equity Awards held by the named executive officers as of December 31, 2011.

Employment and Severance Arrangements

        We entered into employment agreements with Steven J. Newby (dated September 3, 2009), and Matthew S. Harrison (dated September 15, 2011), and we amended and restated Mr. Newby's employment agreement in connection with this offering. Rene Casadaban is currently not a party to an employment agreement; however, we expect to enter into an employment agreement with Mr. Casadaban at or following the completion of this offering. We will first describe the employment agreements as in effect in 2011, and we will then describe Mr. Newby's amended and restated agreement.

        Mr. Newby's original employment agreement was scheduled to expire on August 31, 2012. Mr. Harrison's employment agreement has an initial term of two years, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 90 days prior to the expiration of the then-applicable term. Each employment agreement provides for the named executive officer's initial base salary and a performance-based bonus ranging from 0% to 150% of base salary, with a target of 75% of base salary. Mr. Harrison's employment agreement also provides for a $25,000 cash signing bonus, reimbursement for up to $60,000 in relocation expenses incurred in relocating to Atlanta, Georgia, and reimbursement for tax preparation

153

---

Table of Contents

expenses in the amount of $10,000 per year. No such reimbursements were paid to Mr. Harrison in 2011.

        Each employment agreement provides for a cash severance payment upon a termination by us without cause or by the named executive officer for good reason, which is defined generally as the named executive officer's termination of employment within two years after the occurrence of (i) a material diminution in the named executive officer's authority, duties or responsibilities, (ii) a material diminution in the named executive officer's base compensation, (iii) a material change in the geographic location at which the named executive officer must perform his services under the agreement or (iv) any other action or inaction that constitutes a material breach of the employment agreement by us. Each employment agreement provides that the named executive officer's severance payment will be equal to the sum of his annual base salary and the annual bonus payable in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days in the period beginning on the date of termination and ending on the later of (a) the last day of the then-applicable term of the employment agreement and (b) the first anniversary of the date of termination (the "severance period") and the denominator of which is 365. The severance payment is payable in equal installments during the severance period.

        Following any termination of employment other than one resulting from non-extension of the term, the employment agreements provide that each of Messrs. Newby and Harrison will be subject to a post-termination non-competition covenant through the severance period, and, following any termination of employment, each of Messrs. Newby and Harrison will be subject to a one-year post-termination non-solicitation covenant.

        Under the employment agreements, if the named executive officer's employment is terminated due to non-extension of the term by us or by the named executive officer, we may choose to subject him to a non-competition covenant for up to one year post-termination. If we exercise this "noncompete option", then the named executive officer will be entitled to a severance payment in an amount equal to the sum of his annual base salary and annual bonus payable in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period.

        Any severance payment payable to a named executive officer pursuant to his employment agreement will be subject to his execution and non-revocation of a release of claims in favor of us.

        We entered into Mr. Newby's amended and restated employment agreement on August 13, 2012. The terms of the agreement are generally similar to the terms of his original agreement (described above), except as set forth below. Mr. Newby's amended and restated employment agreement has an initial term of three years (and includes the same provisions regarding potential extensions as his original agreement). The agreement provides for an annual base salary of $400,000 and an annual performance-based bonus with the same target and range as in his previous agreement. Unlike the original agreement, the amended and restated agreement provides that Mr. Newby will receive a prorated annual bonus (based on target) if his employment is terminated by us without cause or due to death or disability.

        Mr. Newby's amended and restated employment agreement provides for certain additional perquisites that were not in his original agreement. It provides that we will reimburse him for tax preparation services and ongoing tax advice up to $10,000 per year, as well as an annual executive physical at a medical facility of his choice.

        Under the amended and restated agreement, upon a termination of employment by us without cause or by Mr. Newby for good reason other than in the period beginning six months prior to a

154

---

Table of Contents

change in control of us and ending on the 12-month anniversary of such a change in control, Mr. Newby's severance payment will be equal to the sum of his annual base salary and his annual bonus payable in respect of the immediately preceding year. If such a termination occurs during the period beginning six months prior to a change in control of us and ending on the 12-month anniversary of such a change in control, Mr. Newby's severance payment will increase to two times the sum of his annual base salary and the immediately preceding year's bonus.

        Mr. Newby's employment agreement also provides that all equity awards granted to Mr. Newby under the LTIP (as described below) upon or following this offering and held by him as of immediately prior to a change in control of us will become fully vested immediately prior to the change in control. As described above, the Pre-IPO Equity Awards provide for certain acceleration in the event of certain terminations of employment, including certain terminations in connection with a change in control.

        Mr. Newby's employment agreement provides that, if any portion of the payments or benefits provided to Mr. Newby would be subject to the excise tax imposed in connection with Section 280G of the Internal Revenue Code, then the payments and benefits will be reduced if such reduction would result in a greater after-tax payment to Mr. Newby.

2012 Long-Term Incentive Plan

        Prior to the consummation of this offering, our general partner intends to adopt a 2012 Long-Term Incentive Plan, or LTIP, pursuant to which our, our subsidiaries' and our general partner's eligible officers (including the named executive officers), employees, consultants and directors will be eligible to receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to our performance. The description of the LTIP set forth below is a summary of the anticipated material features of the LTIP. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the LTIP. In addition, our general partner is still in the process of implementing the LTIP and, accordingly, this summary is subject to change prior to the effectiveness of the registration statement of which this prospectus is a part.

        The LTIP will provide for the grant, from time to time at the discretion of the board of directors or compensation committee of our general partner, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of                        common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited will be available for delivery pursuant to other awards. We expect that the LTIP will be administered by our general partner's board of directors, though such administration function may be delegated to a committee (including the compensation committee) that may be appointed by the board to administer the LTIP. The LTIP will be designed to promote our interests, as well as the interests of our unitholders, by rewarding the officers, employees, consultants and directors of us, our subsidiaries and our general partner for delivering desired performance results, as well as by strengthening our and our general partner's ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

        In connection with the closing of this offering, the board of directors of our general partner will grant $50,000 of restricted units to two of our directors and will grant up to $2.5 million in phantom units with distribution equivalent rights to certain key employees that provide services for us, including executive officers, pursuant to our long-term incentive plan. Of the employee units, $350,000, $295,000 and $175,000 of units will be granted to Messrs. Newby, Harrison and Casadaban, respectively. The phantom units to be granted to our NEOs and other employees are expected to vest on the third anniversary of the consummation of this offering. Holders of phantom units will also receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to

155

---

Table of Contents

the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date.

Restricted Units and Phantom Units

        A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

        Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

        The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

        The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

        Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

        Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

        The LTIP may also permit the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of an other unit-based award may be based on a participant's continued service, the achievement of performance

156

---

Table of Contents

criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units; Cost

        Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Amendment or Termination of Long-Term Incentive Plan

        The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

157

---

Table of Contents

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The following table sets forth certain information regarding the beneficial ownership of units following the closing of this offering and the related transactions by:

•

each person who is known to us to beneficially own 5% or more of such units to be outstanding;



•

our general partner;



•

each of the directors and named executive officers of our general partner; and



•

all of the directors and executive officers of our general partner as a group.

        All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

        The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of                        , 2012, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

158

---

Table of Contents

        The percentage of units beneficially owned is based on a total of                        common units and                        subordinated units outstanding immediately following this offering.

159

---

Table of Contents

160

---

Table of Contents

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

        Immediately following the closing of this offering, Summit Investments will own                        common units and                         subordinated units, representing a combined        % limited partner interest in us (or                        common units and                        subordinated units, representing a combined         % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, Summit Investments will own and control our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to our General Partner and its Affiliates

        The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and our liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Formation Stage

Operational Stage

161

---

Table of Contents

Liquidation Stage

Agreements with Affiliates

        We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

Promissory Notes

        In conjunction with the purchase of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million and had an 8% interest rate and a maturity date of October 27, 2013. The outstanding balance under the notes was paid in full on July 2, 2012.

EquiPower Electricity Management Services Agreement

        In December 2011, we entered into a consulting arrangement with EquiPower Resources Corp., or EquiPower, an affiliate of Energy Capital Partners, whereby EquiPower assists us with managing our electricity price risk. During the year ended December 31, 2011, we paid EquiPower $11,000 for such services. Curtis A. Morgan, a member of the board of directors of our general partner, is the President and Chief Executive Officer of EquiPower.

162

---

Table of Contents

DFW Class B Membership Interests

        Certain current and former employees and members of management, or the DFW employees, of DFW Midstream Management, LLC, or DFW Management, hold Class B membership interests representing an aggregate 4.4% net profits interests in DFW Midstream Services, LLC, or DFW Midstream. The net profits interests allow the DFW employees to share in distributions by DFW Midstream only after we have received distributions in an amount equal to any capital contributions made subsequent to the date of grant, subject to the terms set forth in the underlying award agreement and the limited liability company agreement of DFW Management.

        The net profits interests were granted subject to four-year vesting schedules, and provide for accelerated vesting in certain circumstances, including termination without cause or by reason of death or disability. Unvested profits interests are forfeited upon termination for any other reason. Pursuant to the DFW Midstream limited liability company agreement, the vested net profits interests are subject to a repurchase right, at our option, for one year following the holder's termination of employment. In the event of the termination of an employee's employment due to death, disability, termination by DFW Midstream without cause or a voluntary resignation after the fourth anniversary of the employee's start date with DFW Midstream, the repurchase price will be equal to the value of the net profits interests in a hypothetical liquidation of DFW Midstream pursuant to the rights and preferences set forth in the limited liability agreement, assuming all assets were sold for their fair market value.

        Four former DFW employees, who own an aggregate 4.1% vested net profits interests in DFW Midstream, have indicated that they may file suit against DFW Midstream, Summit Investments and their affiliates regarding an alleged failure to make distributions in respect of the net profits interests granted to them prior to their separation from DFW Midstream, and an alleged failure to repurchase their interests under the terms of the limited liability agreement. We believe that these allegations are without merit. While the limited liability company agreement provides us with an option to repurchase the net profits interests held by three of the former DFW employees pursuant to the terms of that agreement, and at the hypothetical liquidation price described above, we do not believe we are under any obligation to repurchase any of the former employees' interests or, until such time as we have received distributions in an amount equal to the capital contributions made subsequent to their date of grant, to make any distributions in respect of those interests. We intend to vigorously defend ourselves against these allegations, and we do not believe that the dispute, even if determined adversely against us, would have a material effect on our financial position, results of operations or cash flows.

Procedures for Review, Approval and Ratification of Related-Person Transactions

        The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate and subject to obtaining the approval of members representing a majority interest in our general partner, authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

        The code of business conduct and ethics will provide that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

        The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

163

---

Table of Contents

CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

        Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Energy Capital Partners and GE Energy Financial Services), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have duties to manage our general partner in a manner they subjectively believe is in the best interests of its owners. At the same time, the directors and executive officers of our general partner have a duty to manage us in a manner they subjectively believe is in our best interests.

        The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the duties (including fiduciary duties) owed by a general partner to the limited partners and the partnership, except for the implied contractual covenant of good faith and fair dealing. As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods for resolving conflicts of interest. Our partnership agreement also specifically defines the duties our general partner owes to us and our unitholders with respect to actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

        Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the Conflicts Committee. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the Conflicts Committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.

        Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•

approved by the Conflicts Committee;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;



•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        If the resolution or course of action taken with respect to the conflict of interest satisfies any of the standards set forth in the first, third or fourth bullet points above, then such resolution or course of action will be deemed to be approved by all of our unitholders and, in the case of all four bullet points above, will not constitute a breach of our partnership agreement or of any duties our general partner may owe us or our unitholders.

        Our partnership agreement provides that our conflicts committee may be comprised of one or more independent directors. If we establish a conflicts committee with only one independent director,

164

---

Table of Contents

your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

        Our general partner may, but is not required to, seek approval from the Conflicts Committee of a resolution of a conflict of interest with our general partner or affiliates. Any matters approved by the Conflicts Committee will be presumed to have been approved in good faith. If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and, in each case, in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in our best interests. Please read "Management—Committees of the Board of Directors—Conflicts Committee" for information about the Conflicts Committee.

        Conflicts of interest could arise in the situations described below, among others.

Affiliates of our general partner may compete with us. Neither our partnership agreement nor any other agreement requires Summit Investments to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow.

        Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including Energy Capital Partners and GE Energy Financial Services, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, Energy Capital Partners and GE Energy Financial Services, through their investment funds and managed accounts, make investments and purchase entities in various areas of the energy sector, including the midstream natural gas industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, Energy Capital Partners and GE Energy Financial Services. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own an interest in entities that compete with us.

Our general partner is allowed to take into account the interests of parties other than us, such as Energy Capital Partners, in resolving conflicts.

        Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in

165

---

Table of Contents

its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner's limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties and limits our general partner's liabilities and the rights of our unitholders with respect to actions that might otherwise constitute breaches of fiduciary duty under applicable Delaware law.

        In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. For example, our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;



•

provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, which means the subjective belief that the decision is in our best interests;



•

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) "fair and reasonable" to us, provided that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and



•

provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its executive officers or directors acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

        Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general

166

---

Table of Contents

partner has sought Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;



•

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;



•

the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;



•

the negotiation, execution and performance of any contracts, conveyances or other instruments;



•

the distribution of our cash;



•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;



•

the maintenance of insurance for our benefit and the benefit of our partners;



•

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;



•

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;



•

the indemnification of any person against liabilities and contingencies to the extent permitted by law;



•

the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and



•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

        Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in "good faith," our general partner must have a subjective belief that the determination is in our best interests. Please read "The Partnership Agreement—Voting Rights" for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

        The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•

the amount and timing of asset purchases and sales;



•

cash expenditures and the amount of estimated reserve replacement expenditures;



•

borrowings;



•

the issuance of additional units; and

167

---

Table of Contents

•

the creation, reduction or increase of reserves in any quarter.

        Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

        In addition, our general partner may use an amount, initially equal to $             million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

        In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or



•

hastening the expiration of the subordination period.

        For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

        We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read "Certain Relationships and Related Party Transactions."

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

        Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm's-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.

        Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.

168

---

Table of Contents

        Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner's limited call right.

        Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us free of any liability or obligation to us or our unitholders. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

        Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

        The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our public common unitholders in certain situations.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial minimum quarterly distribution and target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution

169

---

Table of Contents

levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distribution of Available Cash—General Partner Interest and Incentive Distribution Rights."

Duties of Our General Partner

        The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the duties (including fiduciary duties) owed by the general partner to limited partners and the partnership, except for the implied contractual covenant of good faith and fair dealing.

        Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods for resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our general partner in a manner it believes is in the best interests of its owners. Without these provisions, our general partner's ability to make decisions involving conflicts of interest would be restricted. The replacement of fiduciary standards enable our general partner to take into consideration the interests of all parties involved. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions may be detrimental to our unitholders, however, because they restrict the rights and remedies that would otherwise be available to unitholders for actions that might otherwise constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

•

the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary;



•

the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware law on our general partner; and



•

certain rights and remedies of limited partners contained in the Delaware Act.

170

---

Table of Contents

171

---

Table of Contents

172

---

Table of Contents

        By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

        Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read "The Partnership Agreement—Indemnification."

173

---

Table of Contents

DESCRIPTION OF OUR COMMON UNITS

The Units

        The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

                                 will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by our unitholders:

•

surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;



•

special charges for services requested by a holder of a common unit; and



•

other similar fees or charges.

        There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

        The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

        By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;



•

represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and



•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

174

---

Table of Contents

        Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

        We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

        Common units are securities and are transferable according to the laws governing the transfer of securities.

        Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

175

---

Table of Contents

THE PARTNERSHIP AGREEMENT

        The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

        We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•

with regard to distributions of available cash, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions";



•

with regard to the duties of our general partner, please read "Conflicts of Interest and Duties";



•

with regard to the transfer of common units, please read "Description of Our Common Units—Transfer of Common Units"; and



•

with regard to allocations of taxable income and taxable loss, please read "Material Federal Income Tax Consequences."

Organization and Duration

        We were organized in Delaware in May 2012 and have a perpetual existence.

Purpose

        Our purpose under our partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

        Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than the business of gathering, compressing and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, other than the implied contractual covenant of good faith and fair dealing. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

        Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership interests as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

Capital Contributions

        Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

        For a discussion of our general partner's right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read "—Issuance of Additional Securities."

176

---

Table of Contents

Voting Rights

        The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a "unit majority" require:

•

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and



•

after the subordination period, the approval of a majority of the outstanding common units.

        By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

        In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing.

177

---

Table of Contents

Limited Liability

        Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

•

to remove or replace our general partner;



•

to approve some amendments to our partnership agreement; or



•

to take other action under our partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

        Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the

178

---

Table of Contents

extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

        Our subsidiaries conduct business in two states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

        Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

        Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.

        It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

        In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

        Upon issuance of additional partnership interests (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner's 2.0% interest in us will be reduced if we issue additional units in the future (other than in those circumstances described above) and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests

179

---

Table of Contents

whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

        Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of our partnership or our unitholders, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

        No amendment may be made that would:

•

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or



•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

        The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon the closing of this offering, affiliates of our general partner will own approximately        % of the outstanding common and subordinated units.

No Unitholder Approval

        Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;



•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;



•

a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

180

---

Table of Contents

•

a change in our fiscal year or taxable year and related changes;



•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;



•

an amendment that our general partner determines to be necessary or appropriate in connection with the authorization of issuance of additional partnership interests or rights to acquire partnership interests;



•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;



•

an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;



•

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;



•

mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or



•

any other amendments substantially similar to any of the matters described above.

        In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;



•

are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;



•

are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the units are or will be listed for trading;



•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or



•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.


Opinion of Counsel and Limited Partner Approval

        Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under "—No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

181

---

Table of Contents

        In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90.0% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Sale or Other Disposition of Assets

        A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our unitholders, other than the implied contractual covenant of good faith and fair dealing.

        In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries' assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries' assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries' assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20.0% of our outstanding partnership interests immediately prior to the transaction.

        If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

182

---

Table of Contents

Termination and Dissolution

        We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following the approval and admission of a successor general partner;



•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;



•

the entry of a decree of judicial dissolution of our partnership; or



•

there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

        Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•

the action would not result in the loss of limited liability of any limited partner; and



•

neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

        Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of Our General Partner

        Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to                        , 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                        , 2022 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" and "—Transfer of Incentive Distribution Rights."

183

---

Table of Contents

        Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

        Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, and a majority of the outstanding subordinated units, voting as a single class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, affiliates of our general partner will own        % of the outstanding common and subordinated units.

        Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

•

the subordination period will end, and all subordinated units will immediately and automatically convert into common units on a one-for-one basis;



•

all cumulative arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

        In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

        If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

        In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred

184

---

Table of Contents

in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

        Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

•

an affiliate of our general partner (other than an individual); or



•

another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to such entity,

our general partner may not transfer all or any of its general partner interest to another person prior to                        , 2022 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

        Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

        At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

        Our general partner may transfer any or all of its incentive distribution rights to an affiliate or a third party without unitholder approval.

Change of Management Provisions

        Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read "—Meetings; Voting."

Limited Call Right

        If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be

185

---

Table of Contents

selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

•

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and



•

the average of the daily closing prices of the partnership interests of such class for the 20 consecutive trading days preceding the date three days before the date the notice is mailed.

        As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units."

Meetings; Voting

        Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

        Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

        Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

186

---

Table of Contents

        Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

        By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Redemption of Ineligible Holders

        In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that may be subject to rate regulation by FERC or an analogous regulatory body in the future, each transferee of common units, upon becoming the record holder of such common units, will automatically certify, and the general partner at any time can request such unitholder to re-certify:

•

that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or



•

that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity's owners are subject to United States federal income taxation on the income generated by us.

        Furthermore, in order to avoid a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest as the result of any federal, state or local law or regulation concerning the nationality, citizenship or other related status of any unitholder, our general partner may at any time request unitholders to certify as to, or provide other information with respect to, their nationality, citizenship or other related status.

        The certifications as to taxpayer status and nationality, citizenship or other related status can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

        If a unitholder fails to furnish the certification or other requested information with 30 days or if our general partner determines, with the advice of counsel, upon review of such certification or other information that a unitholder does not meet the status set forth in the certification, we will have the right to redeem all of the units held by such unitholder at the market price as of the date three days before the date the notice of redemption is mailed.

        The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5.0% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

187

---

Table of Contents

Indemnification

        Under our partnership agreement, we will indemnify the following persons, in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•

our general partner;



•

any departing general partner;



•

any person who is or was an affiliate of our general partner or any departing general partner;



•

any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of our subsidiaries, us or any entity set forth in the preceeding three bullet points;



•

any person who is or was serving at the request of the general partner or any departing general partner or any of their affiliates as an officer, director, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries; and



•

any person designated by our general partner.

        Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

        Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

        Our general partner is required to keep or cause to be kept appropriate books and records of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.

        We will furnish or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants, including a balance sheet and statements of operations, and our equity and cash flows. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

        We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to

188

---

Table of Contents

assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

        Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:

•

a current list of the name and last known address of each record holder;



•

copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and



•

certain information regarding the status of our business and financial condition.

        Our general partner may, and intends to, keep confidential from the limited partners any information that our general partner reasonably believes to be in the nature of trade secrets or other information the disclosure of which our general partner in good faith believes is not in our best interests or could damage us or our business or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

        Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Summit Midstream GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

189

---

Table of Contents

UNITS ELIGIBLE FOR FUTURE SALE

        After the sale of the common units offered by this prospectus, Summit Investments will hold an aggregate of                        common units and                        subordinated units (or                        common units and                        subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

        The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1.0% of the total number of the securities outstanding; or



•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

        Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule's public information requirements, volume limitations, manner of sale provisions and notice requirements.

        Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."

        Under our partnership agreement, our general partner and its affiliates, excluding any individual who is an affiliate of our general partner, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

        Summit Investments, our general partner, each of our general partner's directors and officers and other owners have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Please read "Underwriting" for a description of these lock-up provisions.

190

---

Table of Contents

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

        This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Summit Midstream Partners, LP and our operating subsidiaries.

        The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose "functional currency" is not the U.S. dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

        No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

        All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

        For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and

191

---

Table of Contents

(iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").

Partnership Status

        A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than        % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

        No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•

We will be classified as a partnership for federal income tax purposes; and



•

Each of our operating subsidiaries will be disregarded as an entity separate from us for federal income tax purposes.

        In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

•

Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and



•

For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

        We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

        If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed

192

---

Table of Contents

corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

        If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

        The discussion below is based on Latham & Watkins LLP's opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

        Unitholders of Summit Midstream Partners, LP will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes.

        A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

        Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding common units in Summit Midstream Partners, LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Summit Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

        Subject to the discussion below under "—Entity-Level Collections," we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

193

---

Table of Contents

Treatment of Distributions

        Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units." Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

        A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

        We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending                                    , 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

        The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

194

---

Table of Contents

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

        A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner's "net value" as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses

        The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

        In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

        In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in

195

---

Table of Contents

other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

        A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

        The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;



•

our interest expense attributed to portfolio income; and



•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

        The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

        If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

        In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

196

---

Table of Contents

        Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together referred to in this discussion as the "Contributed Property." The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, "reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

        An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•

his relative contributions to us;



•

the interests of all the partners in profits and losses;



•

the interest of all the partners in cash flow; and



•

the rights of all the partners to distributions of capital upon liquidation.

        Latham & Watkins LLP is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

        A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;



•

any cash distributions received by the unitholder as to those units would be fully taxable; and



•

all of these distributions would appear to be ordinary income.

197

---

Table of Contents

        Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

        Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

        Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. These rates are scheduled to sunset after December 31, 2012, and, further, are subject to change by new legislation at any time.

        The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010 is scheduled to impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

        We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets ("common basis") and (ii) his Section 743(b) adjustment to that basis.

        We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is

198

---

Table of Contents

subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Units."

        We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units." A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." Latham & Watkins LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

        A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

        The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the

199

---

Table of Contents

Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

        We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Initial Tax Basis, Depreciation and Amortization

        The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

        To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read "—Uniformity of Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

        If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

        The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

200

---

Table of Contents

Valuation and Tax Basis of Our Properties.

        The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

        Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

        Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

        Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

        The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the

201

---

Table of Contents

holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

        Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;



•

an offsetting notional principal contract; or



•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

        Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

        In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

        Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated

202

---

Table of Contents

items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

        A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

        We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

        Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754

203

---

Table of Contents

Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under "—Tax Consequences of Unit Ownership—Section 754 Election," Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

        Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

        Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

        In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

        A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published

204

---

Table of Contents

by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

        We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

        The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

        Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

        The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

        A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return.

205

---

Table of Contents

Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

        Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;



•

whether the beneficial owner is:



•

a person that is not a U.S. person;



•

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or



•

a tax-exempt entity;



•

the amount and description of units held, acquired or transferred for the beneficial owner; and



•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

        Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

        An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

        For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, "substantial authority"; or



•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

        If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

206

---

Table of Contents

        A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

        In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

        If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

        Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties";



•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and



•

in the case of a listed transaction, an extended statute of limitations.

        We do not expect to engage in any "reportable transactions."

Recent Legislative Developments

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read "—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

207

---

Table of Contents

State, Local, Foreign and Other Tax Considerations

        In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property and do business in Texas and Colorado. Colorado imposes a personal income tax on individuals, and both Texas and Colorado impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

        It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

208

---

Table of Contents

INVESTMENT IN SUMMIT MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

        An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, "Similar Laws." For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements, collectively, "Employee Benefit Plans." Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;



•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;



•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read "Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors"; and



•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

        The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

        Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving "plan assets" with parties that, with respect to the Employee Benefit Plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

        In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

        The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed "plan assets." Under these rules, an entity's assets would not be considered to be "plan assets" if, among other things:

•

(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

209

---

Table of Contents

•

(b) the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or



•

(c) there is no significant investment by "benefit plan investors," which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

        Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

        In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

210

---

Table of Contents

UNDERWRITING

        Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

        The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

•

the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;



•

the representations and warranties made by us to the underwriters are true;



•

there is no material change in our business or the financial markets; and



•

we deliver customary closing documents to the underwriters.

Commissions and Expenses

        The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

        We will pay a structuring fee equal to        % of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. for the evaluation, analysis and structuring of our partnership. Additionally, we have agreed to pay Tudor, Pickering, Holt & Co. Securities, Inc. ("TPH"), which is not an underwriter of this offering, an advisory fee of $1.75 million for services provided in connection with the evaluation, analysis and structuring of our partnership in a pre-offering context. We have agreed to pay TPH a quarterly fee equal to $125,000, payable at the beginning of each quarter, commencing as of July 1, 2011 and expiring on the earlier of the termination of the agreement or the completion of this offering. This quarterly fee will be fully creditable against the $1.75 million advisory fee. Furthermore, we have agreed to reimburse TPH for its reasonable out-of-pocket expenses, including the fees and expenses of its legal counsel, resulting from or arising out of its engagement and the performance of its obligations thereunder. Such expenses are capped at $50,000.

211

---

Table of Contents

        The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $            per common unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

        We estimate that the expenses of this offering incurred by us will be $             million (excluding underwriting discounts and commissions and a structuring fee).

Option to Purchase Additional Common Units

        We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of                                    additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than                                    common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

        We, our general partner and its affiliates, including Summit Investments, and the directors and executive officers of our general partner have agreed that, without the prior written consent of Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

        The 180-day restricted period described in the preceding paragraph will be extended if:

•

during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or



•

prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of the material event unless such extension is waived in writing by Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated.

212

---

Table of Contents

        Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release the common units and other securities from lock-up agreements, Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

Offering Price Determination

        Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated among the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

•

the history and prospects for the industry in which we compete;



•

our financial information;



•

the ability of our management and our business potential and earning prospects;



•

the prevailing securities markets at the time of this offering; and



•

the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

        We and certain of our affiliates, including Summit Investments, have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

        The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.



•

A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of

213

---

Table of Contents

the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.



•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

        These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

        Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

        A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

        Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

        We have applied to list our common units on the New York Stock Exchange under the symbol "SMLP." The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

Discretionary Sales

        The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

214

---

Table of Contents

Stamp Taxes

        If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

        The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. The underwriters and their affiliates have in the past, and may in the future, perform investment banking, commercial banking, advisory and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.

        In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

        Affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are lenders under our amended and restated revolving credit facility and, in that respect, will receive a portion of the net proceeds from this offering.

FINRA

        Because the Financial Industry Regulatory Authority, Inc., or FINRA, is expected to view the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

European Economic Area

        In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a "relevant member state"), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state, an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;



•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant dealer or dealers nominated by the issuer for any such offer; or



•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

215

---

Table of Contents

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

        For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression "2010 PD Amending Directive" means Directive 2010/73/EU.

        We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

United Kingdom

        We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a "recognized collective investment scheme" for the purposes of FSMA, or CIS, and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

          (i)  if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended, or the CIS Promotion Order, or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

         (ii)  otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or Financial Promotion Order, or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

        (iii)  in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as "relevant persons"). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

        An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

Switzerland

        This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the

216

---

Table of Contents

public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

        We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or the CISA. Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Germany

        This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

        The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Netherlands

        Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

217

---

Table of Contents

VALIDITY OF THE COMMON UNITS

        The validity of the common units offered hereby will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

        The consolidated financial statements of Summit Midstream Partners, LLC and subsidiaries as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor) included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph related to Summit Midstream Partners, LLC's acquisition of (1) the Grand River system from Encana Corporation on October 27, 2011 and (2) DFW Midstream Services LLC from Energy Future Holdings Corp., effective September 3, 2009). Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The balance sheet of Summit Midstream Partners, LP included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC's web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

        As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website is located at                                    and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

        We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited

218

---

Table of Contents

interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

        Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "will," "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

219

---

Table of Contents

INDEX TO FINANCIAL STATEMENTS

F-1

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-2

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-3

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-4

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-5

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

        Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009. The Company is the predecessor for accounting purposes of Summit Midstream Partners, LP ("SMLP"). The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B membership interests in Summit Midstream (the "SMP Net Profits Interests") through their ownership in Summit Midstream Management, LLC.

        On October 4, 2011, the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590.2 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 to 25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development. The transaction closed on October 27, 2011, with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

        Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

        Basis of Presentation and Principles of Consolidation—The unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The unaudited condensed consolidated financial statements for the six months ended June 30, 2012 also include the operations of Grand River Gathering. The acquisition of Grand River Gathering closed on October 27, 2011. The Company completed the final purchase price allocation to the assets acquired and liabilities assumed during the second quarter of 2012 which has been recorded and presented on a retrospective basis. See Note 3.

F-6

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the results of operations for the six months ended June 30, 2012 and 2011. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). The unaudited condensed consolidated financial statements should be read in conjunction with the audited annual financial statements and related notes elsewhere in this prospectus. The results of operations for an interim period are not necessarily indicative of results expected for a full year. Subsequent events have been evaluated through August 21, 2012, the date these financial statements were available to be issued.

        The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

        Supplemental Unaudited Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, Summit Midstream Partners, LP intends to distribute approximately $             million in cash to the Sponsors. Supplemental unaudited basic and diluted pro forma earnings per common unit for SMLP for the six months ended June 30, 2012 assumed             general partner units,            subordinated units and            common units were outstanding in the period. The            common units consist of             common units issued to the Sponsors plus an additional            units, which is the number of common units that we would have been required to issue to fund the $             million distribution of net proceeds to the Sponsors. The number of common units that SMLP would have been required to issue to fund the $             million distribution was calculated as $             million minus the Summit Midstream Partners, LLC net earnings of $             million for the year ended December 31, 2011 divided by an issue price per unit of $            , which is the initial public offering price of $            per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no securities convertible or exchangeable into common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

        The supplemental unaudited pro forma balance sheet as of June 30, 2012 gives pro forma effect to the assumed distribution discussed in the preceding paragraph, as though it had been declared and was payable as of that date.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Use of Estimates—The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

F-7

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Accounts Receivable—Accounts receivable relates to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At June 30, 2012 and December 31, 2011, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for gathering services during any period presented.

        Goodwill—Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment using a two-step quantitative test. The first step compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired. If the fair value does not exceed the carrying amount the second step compares the implied fair value to the carrying value of the reporting unit. If the carrying amount of a reporting unit's goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment loss.

        Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether future asset retirement obligations exist as of June 30, 2012 and December 31, 2011, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and dehydration facilities, as having an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these assets retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company did not provide any asset retirement obligations as of June 30, 2012 and December 31, 2011 because it does not have sufficient information to reasonably estimate such obligations, and the Company has no current intention of discontinuing use of any significant assets.

        Revenue Recognition—The Company earns revenue from natural gas gathering services provided to natural gas producers and records such revenue as gathering services and other fees. The Company also earns revenue from the sale of physical natural gas retained from its customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. The Company records this revenue as natural gas and condensate sales. The Company records costs incurred which are reimbursed by its customers, on a gross basis in the consolidated statements of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

        The Company's natural gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from certain of its customers. Under these monthly or annual MVCs, the Company's customers agree to ship a minimum volume of natural gas on the Company's gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for an applicable period,

F-8

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

such customer must make a shortfall payment to the Company at the end of that contract month or year, as applicable. Under certain natural gas gathering agreements, customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC, ranging from twelve months to nine years.

        Billings to customers for obligations under their minimum volume commitments are recorded as deferred revenue. The Company recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess volumes of natural gas, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. The Company classifies deferred revenue as short-term for arrangements where the expiration of a customer's right to utilized shortfall payments is twelve months or less. As of June 30, 2012, the Company's customers have been billed $7.6 million of shortfall payments, of which $1.1 million is included in accounts receivable as of June 30, 2012, attributed to arrangements that provide for the ability to offset gathering fees in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.

        Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 10 for a discussion of commitments and contingencies.

        Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

        Comprehensive Income—Comprehensive income is the same as net income for all periods presented.

        Earnings per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

        Unit Based Compensation—Certain of our current and former employees received Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC (collectively, the "Net Profits Interests"). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests are accounted for as compensatory awards. The Net Profits Interests vest ratably over four to five years, and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Company's Amended and Restated Limited Liability Operating Agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the Net Profits Interests as of the

F-9

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

respective grant dates. The Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the Net Profits Interests: (a) assumptions underlying the enterprise value used in connection with the option pricing method, including the discount rate applied to estimated future cash flows, forecasted gathering volumes, revenues and costs, equity performance relative to peer group members, equity market risk premium, enterprise-specific risk premium, and terminal growth rates; (b) holding period restrictions; (c) discounts for lack of marketability; and (d) expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

        Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its condensed consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its condensed consolidated financial statements.

3. ACQUISITION OF GRAND RIVER GATHERING

        The Company completed the acquisition of Grand River Gathering from Encana for $590.2 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 260 miles of pipeline and approximately 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

        The Grand River Transaction closed on October 27, 2011, with an effective date of October 1, 2011. The assets are owned by Grand River Gathering. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million.

        The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised of gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the Grand River Gathering system. The Company completed the final purchase price allocation to the assets acquired and liabilities assumed during the second quarter of

F-10

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. ACQUISITION OF GRAND RIVER GATHERING (Continued)

2012 which has been recorded and presented on a retrospective basis and resulted in the recognition of $45.5 million of goodwill. Management believes the goodwill recorded upon the finalization of the allocation of the purchase price during the three months ended June 30, 2012 represents the incremental value of future cash flow potential attributed to estimated future gathering services within the emerging Mancos and Niobrara Shale developments.

        The final fair values of the assets acquired and liabilities assumed as of October 27, 2011, are as follows:

        During the three months ended June 30, 2012, the acquired assets and assumed liabilities of Grand River Gathering were ultimately determined and the purchase price of the Grand River Transaction was finalized and concluded to be $590.2 million. Additionally, the Company also received the final information needed to value the acquired construction work in process and the intangible assets. As a result, the Company retrospectively recorded an adjustment to decrease its construction work in process by $4.7 million and decrease its intangible assets by $37.9 million based upon the final information received. The Company recorded $1.8 million of deferred revenue related to MVC payments received by the seller prior to the Company's purchase of the business which can be used by the producer to offset future gathering fees. Additionally, $0.9 million of net working capital was recorded representing the final settlement of the remaining acquired assets and assumed liabilities of the Company. These adjustments to the preliminary purchase price and the allocation to the assets acquired and liabilities assumed resulted in the recording of goodwill totaling $45.5 million.

        Unaudited Pro Forma Financial Information —The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the Grand River Transaction had occurred on that date, or what the Company's financial position or results from operations will be for any future periods. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that the Company recorded for the two month period from November 1, 2011 through December 31, 2011. The Company incurred transaction costs of $3,160, which are not included in net

F-11

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. ACQUISITION OF GRAND RIVER GATHERING (Continued)

income presented immediately below, as the pro forma information assumes the transaction occurred January 1, 2010.

4. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL

Identifiable Intangible Assets and Noncurrent Liability

        On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from Texas Competitive Electric Holdings Company LLC (the "DFW Transaction"). The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable intangible assets and a noncurrent liability, which are subject to amortization as of June 30, 2012 and December 31, 2011, are composed of the following:

 

Goodwill

        The Company's goodwill of $45.5 million was recorded in connection with the Grand River Gathering acquisition in October 2011 which has all been allocated to the Company's Grand River Gathering reporting unit. Prior to the completion of this acquisition, the Company never had any goodwill recorded, and thus the Company has never recorded a goodwill impairment.

F-12

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL (Continued)

        Amortization expense of $680 and $816 for the six month periods ended June 30, 2012 and 2011 related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

        Amortization expense of $6,289 for the six month period ended June 30, 2012 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in depreciation and amortization expense in the statements of operations. The intangible asset contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

        Amortization expense of $630 and $389 for the six month periods ended June 30, 2012 and 2011 related to rights-of-way associated with city easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        The unfavorable contract included within noncurrent liability relates to an unfavorable gas gathering contract that was deemed to be below market upon the acquisition of DFW Midstream. Amortization related to the unfavorable gas gathering contract was $865 and $618 for the six month periods ended June 30, 2012 and 2011, and was recorded within revenue. The unfavorable contract is amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

        The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from June 30, 2012 is as follows:

F-13

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. PROPERTY, PLANT, AND EQUIPMENT—NET

        Net property, plant, and equipment is composed of the following:

        Depreciation expense related to property, plant, and equipment was $10,059 and $2,972 for the six months ended June 30, 2012 and 2011. The Company capitalized interest totaling $1,916 and $533 during the six months ended June 30, 2012 and 2011.

6. REVOLVING CREDIT FACILITY

        On May 26, 2011, Holdings closed a senior secured revolving credit facility with total commitments of $285 million. The revolving credit facility, which matures in May 2016, contains a $150 million accordion provision that enables Holdings to increase the total size of the facility any time prior to maturity. The revolving credit facility allows for revolving loans, letters of credit and swingline loans. The revolving credit facility is secured by the membership interests of Holdings and DFW Midstream and substantially all of Holdings' and DFW Midstream's assets and is guaranteed by Holdings' subsidiaries. Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate (LIBOR) plus an applicable margin or a base rate, as defined in the credit agreement.

        The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of June 30, 2012, Holdings was in compliance with all applicable covenants.

        The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners.

        On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior

F-14

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

6. REVOLVING CREDIT FACILITY (Continued)

secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed an additional $163 million under the facility. Additionally, Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. Under the terms of amended and restated revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at June 30, 2012. As of June 30, 2012, unused portion under the amended and restated revolving credit facility totaled $248 million. The unused portion of the amended and restated revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of June 30, 2012 was 2.75%. The amended and restated revolving credit facility matures in May 2016. See Note 7.

7. PROMISSORY NOTES PAYABLE TO SPONSORS

        In conjunction with the purchase of Grand River Gathering, the Company executed promissory notes, on an unsecured basis, with its Sponsors. The notes issued on October 27, 2011, totaled $200 million, mature on October 27, 2013, and have an 8% interest rate. The Company has the option to elect to pay the interest in kind and the Company made this election for all interest due as of June 30, 2012. The amount of interest paid in kind and accrued to the balance of the notes for the six months ended June 30, 2012, is $6,316. During the six months ended June 30, 2012, the Company capitalized $902 of the $6,316 interest expense related to costs incurred on capital projects under construction. On May 8, 2012 the Company borrowed $163 million under the amended and restated revolving credit facility and used a portion of the same borrowings to prepay $160 million of the promissory notes payable to Sponsors. As of June 30, 2012, the aggregate carrying value of these notes approximated the fair value.

        On July 2, 2012, the Company borrowed $50 million under the amended and restated revolving credit facility and used a portion of the same borrowings to prepay the remaining $49.2 million of the promissory notes payable to Sponsors (inclusive of accrued pay in kind interest).

8. INCOME TAXES

        No provision for federal income taxes or state income taxes are included in our results of operations as such income is taxable directly to our owners. However, we are subject to income taxes in the state of Texas. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability

F-15

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

8. INCOME TAXES (Continued)

companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $294 and $367, for the six months ended June 30, 2012 and 2011.

9. MEMBERSHIP INTERESTS

        As of June 30, 2012, Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

        In accordance with the Summit LLC Agreement, capital accounts are maintained for the Company's members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's condensed consolidated financial statements.

        The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests described above.

        Class B membership interests in Summit Midstream Management, LLC (the "SMP Net Profits Interests") participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested SMP Net Profits Interests. The SMP Net Profits Interests are accounted for as compensatory awards. All grants vest ratably over five years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Company's Amended and Restated Limited Liability Operating Agreement).

        During the six months ended June 30, 2012, the Company, with assistance from a third-party valuation expert, determined the fair value of the class B membership interests in Summit Midstream Management, LLC (the "SMP Net Profits Interests") as of the respective grant date for the grant made on January 25, 2012. The SMP Net Profits Interests granted on January 25, 2012, were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class.

F-16

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

9. MEMBERSHIP INTERESTS (Continued)

        A significant input of the option pricing method is the enterprise value of the Company, as well as the length of holding period and volatility of our equity securities. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the Company. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the Company's peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the Company's estimated future cash flows.

        Additional significant inputs used in the option pricing method include the length of holding period, discount for lack of marketability and volatility. The length of the holding period was determined primarily based upon our Sponsors' expectations as of the grant date. The Company, with assistance from a third-party valuation firm, estimated the discount for lack of marketability and volatility. The discount for lack of marketability was estimated using a protective put methodology. The protective put methodology consisted of estimating the cost to insure an investment in the SMP Net Profits Interests over the length of the holding period. Using the Black-Scholes option pricing model, we calculated the cost of a put option for the SMP Net Profits Interests as of the grant date. The discount for lack of marketability is equal to the put option value divided by the value of the underlying membership interest. We estimated the expected volatility of the SMP Net Profits Interests based on the historical and implied volatilities of the securities of publicly-traded peer companies using data from Standard & Poor's Capital IQ proprietary research tool. The expected volatility conclusions were based on consideration of both the historical and implied volatilities of the publicly-traded peer companies as of the grant date. These inputs used in the option pricing method for the SMP Net Profits Interests granted on January 25, 2012 are as follows:

        Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests as of June 30, 2012 is presented below.

F-17

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

9. MEMBERSHIP INTERESTS (Continued)

        The Company recognizes compensation expense ratably over the five year vesting period. Non-cash compensation expense (recorded in general and administrative expense) related to the six months ended June 30, 2012 and 2011 was $613 and $328. The Company also recorded non-cash compensation expense of $463 during the six months ended June 30, 2011 related to 2010 and 2009. As of June 30, 2012, the unrecognized non-cash compensation expense for the remaining vesting period is $4,248. Incremental non-cash compensation expense will be recorded over the remaining expected weighted average vesting period of 3.9 years.

        Class B membership interests in DFW Midstream Management LLC (the "DFW Net Profits Interests") participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. All grants vest ratably over four years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement).

        Information regarding the amount and grant-date fair value of the vested and nonvested DFW Net Profits Interests as of June 30, 2012 is presented below.

        The Company recognizes compensation expense ratably over the four year vesting period. Non-cash compensation expense (recorded in general and administrative expense) related to the six months ended June 30, 2012 and 2011 was $800 and $568. The Company also recorded non-cash compensation expense of $582 in the six months ended June 30, 2011 related to 2010 and 2009. As of June 30, 2012, the unrecognized non-cash compensation expense for the remaining vesting period is $520. Incremental non-cash compensation expense will be recorded over the remaining expected weighted average vesting period of 2.2 years.

10. COMMITMENTS AND CONTINGENCIES

        Contractual Commitments—The Company leases office space in Dallas, Texas, Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas, and has determined that its leases are classified as operating leases.

        Total rent expense related to operating leases was $315 and $162 for the six month periods ended June 30, 2012 and 2011, and was recorded within general and administrative.

F-18

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. COMMITMENTS AND CONTINGENCIES (Continued)

        Legal Proceedings—The Company is involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on the Company's financial condition, results of operations, or liquidity.

11. RELATED-PARTY TRANSACTIONS

        Promissory Notes Payable to Sponsors—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 7)

        Electricity Management Services Agreement—The Company entered into a consulting arrangement with Equipower Resources Corp. ("Equipower"), an affiliate of Energy Capital Partners, whereby Equipower assists the Company with managing its electricity price risk. During the six month periods ended June 30, 2012 and 2011, the Company paid Equipower $88 and zero for such services.

        Diligence Expenses—In the past, the Sponsors reimbursed the Company for transactional due diligence expenses related to proposed transactions that were not completed. As of June 30, 2012 and December 31, 2011, the Company had a receivable from the Sponsors of $0 and $1,309, respectively, for similar expenses. During the six months ended June 30, 2012 the company was reimbursed $319 while $990 was not paid.

12. CONCENTRATIONS OF RISK

        Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and accounts receivable. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.

        Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale of natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the Company's customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

        For the six month periods ended June 30, 2012 and 2011, the Company had three customers (each comprising over 10% of total revenue) that accounted for approximately 61% and 58% of total revenue. The total accounts receivable from these customers accounted for approximately 60% and 51% of accounts receivable as of June 30, 2012 and December 31, 2011.

F-19

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. CONCENTRATIONS OF RISK (Continued)

        The following tables summarize concentrations of revenue in excess of 10% of total revenue for the six month periods ended June 30, 2012 and 2011, and accounts receivable in excess of 10% of accounts receivable as of June 30, 2012 and December 31, 2011:

******

F-20

---

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC
Dallas, Texas

        We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LLC and subsidiaries (the "Company") as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, (Successor) and for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor), and for the period from January 1, 2009 through September 3, 2009 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 4 to the consolidated financial statements, the Company acquired Grand River Gathering Company, LLC on October 27, 2011. Also, as discussed in Note 3 to the consolidated financial statements, the Company acquired a controlling interest in DFW Midstream Services LLC on September 3, 2009.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012 (August 21, 2012 as to the retrospective effects of the finalization of the accounting for the Grand River Gathering Company, LLC acquisition described in Notes 1 and 4)

F-21

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-22

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-23

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

 

   

The accompanying notes are an integral part of these consolidated financial statements.

F-24

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

F-25

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-26

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

        Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009 (inception). The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B Units in Summit Midstream through their ownership in Summit Midstream Management, LLC.

        Concurrent with the Company's formation on September 3, 2009, the Company acquired a controlling interest in DFW Midstream Services LLC ("DFW Midstream"), and accordingly, the DFW Midstream Limited Liability Company Agreement was amended and restated to effect among other things (i) the continuation of Texas Competitive Electric Holdings Company LLC ("TCEH") as a Class A Member, (ii) the admission of Summit Midstream as a Class A Member, (iii) the admission of DFW Midstream Management LLC as the Class B Member, and (iv) the continuation of DFW Midstream as a Delaware limited liability company. The acquisition of a controlling interest in DFW Midstream by Summit Midstream was accounted for under the acquisition method of accounting. Summit Midstream's consolidated financial statements reflect DFW Midstream's operations for all periods presented.

        On June 2, 2010, Summit Midstream purchased all of TCEH's remaining membership interests in DFW Midstream. The transaction was completed on June 18, 2010. The purchase of the remaining noncontrolling interest in DFW Midstream was accounted for as an equity transaction (see Note 10).

        On October 4, 2011 the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590.2 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10-25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development. The transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

F-27

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream and Grand River Gathering. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

        Basis of Presentation—The consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The consolidated financial statements for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, reflect the application of purchase accounting related to the acquisition of a controlling interest in DFW Midstream by Summit Midstream on September 3, 2009. The consolidated financial statements also include the operations of Grand River Gathering upon the closing of the transaction on October 27, 2011. The Company completed the final purchase price allocation to the assets acquired and liabilities assumed during the second quarter of 2012 which has been recorded and presented on a retrospective basis. (See Note 4)

        The consolidated financial statements provided for the period from January 1, 2009 through September 3, 2009, include only the operations of DFW Midstream which is the predecessor of Summit Midstream. These financial statements represent the results of operations, changes in membership interest and cash flows of DFW Midstream and have been carved out of the accounting records maintained by Energy Future Holdings Corp. and its subsidiaries ("Energy Future Holdings"). Historically, Energy Future Holdings did not allocate general and administrative ("G&A") expenses to DFW Midstream for any centralized finance and administrative costs. Accordingly, the financial statements for the period from January 1, 2009 through September 3, 2009 (inception) include an estimate of G&A for the period of $588 based on the level of significance of DFW Midstream to Energy Future Holdings, the number of employees directly involved in DFW Midstream and considering the capital intensive nature of the activities of DFW Midstream during this period. The estimate of G&A expenses was predominantly related to rent, insurance and other employee related expenses. Because of the nature of these carved-out financial statements, the intercompany advances from Energy Future Holdings were reported within an intercompany advances account, and immediately prior to the acquisition, were converted to membership interest.

        All intercompany transactions have been eliminated upon consolidation. Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

        The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

F-28

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        The Company is the predecessor for accounting purposes of Summit Midstream Partners, LP ("SMLP") who submitted a registration statement for its initial public offering of common units on a confidential basis.

        Supplemental Unaudited Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, SMLP intends to distribute approximately $             million in cash to the Sponsors. Supplemental unaudited basic and diluted pro forma earnings per common unit for Summit Midstream Partners, LP for the year ended December 31, 2011 assumed                         general partner units,                         subordinated units and                        common units were outstanding in the period. The                        common units consists of             common units issued to the Sponsors plus an additional                        units, which is the number of common units that we would have been required to issue to fund the $             million distribution of net proceeds to the Sponsors. The number of common units that SMLP would have been required to issue to fund the $             million distribution was calculated as $             million minus the Company's net earnings of $37.4 million for the year ended December 31, 2011 divided by an issue price per unit of $            , which is the initial public offering price of $            per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no potential common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Use of Estimates—The consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

        Cash and Cash Equivalents—Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

        Accounts Receivable—Accounts receivable relate to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At December 31, 2011 and 2010, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for services during any period presented.

        Intangible Assets and Liabilities—Intangible assets and unfavorable contracts consisting of favorable and unfavorable gas gathering contracts are amortized on a units-of-production basis over the life of the contract, which is the period over which the contracts are expected to contribute directly or indirectly to the Company's future cash flows. The favorable and unfavorable contracts relate to gas

F-29

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

gathering contracts that were deemed to be above or below market at the acquisition of DFW Midstream. The contract lengths range from 10 years to 20 years.

        Intangible assets consisting of contract values related to the Grand River Gathering gas gathering agreements are amortized over the period of economic benefit based upon the expected revenues over the life of the contract, which range from 10 years to 25 years.

        Right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way are amortized over the shorter of the contractual term of the rights-of-way, ranging from 20 years to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        Property, Plant, and Equipment—Property, plant, and equipment are recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

        Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

        Impairment of Long-Lived Assets—Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows. The Company did not recognize any impairment of long-lived assets during any period presented.

        Other Noncurrent Assets—Other noncurrent assets primarily consist of external costs incurred in connection with the closing of the Company's revolving credit facility and costs incurred related to the Company's contemplated initial public offering. Deferred loan costs are capitalized and amortized over

F-30

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

the life of the related agreement. Amortization of deferred loan costs is included in interest expense in the statement of operations.

        Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether any future asset retirement obligations exist as of December 31, 2011 and 2010, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and dehydration facilities, have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company did not provide any asset retirement obligations as of December 31, 2011 and December 31, 2010 because it does not have sufficient information to reasonably estimate such obligations, and the Company has no current intention of discontinuing use of any significant assets.

        Goodwill—Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment using a two-step quantitative test. The first step compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired. If the fair value does not exceed the carrying amount the second step compares the implied fair value to the carrying value of the reporting unit. If the carrying amount of a reporting unit's goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment loss.

        Revenue Recognition—The Company earns revenue from natural gas gathering services provided to natural gas producers and records such revenue as gathering services and other fees. The Company also earns revenue from the sale of physical natural gas retained from its customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. The Company records this revenue as natural gas and condensate sales. The Company records costs incurred which are reimbursed by its customers, on a gross basis in the consolidated statements of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

        The Company's natural gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from certain of its customers. Under these monthly or annual MVCs, the Company's customers agree to ship a minimum volume of natural gas on the Company's gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for an applicable period,

F-31

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

such customer must make a shortfall payment to the Company at the end of that contract month or year, as applicable. Under certain natural gas gathering agreements, customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC, ranging from twelve months to ten years.

        Billings to customers for obligations under their minimum volume commitments are recorded as deferred revenue. The Company recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess volumes of natural gas, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. The Company classifies deferred revenue as short-term for arrangements where the expiration of a customer's right to utilized shortfall payments is twelve months or less.

        Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 8 for a discussion of commitments and contingencies.

        Environmental Matters—The operations of the Company and the Predecessor are subject to various federal, state and local laws and regulations relating to the protection of the environment. Although the Company believes that it is in compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation, and there can be no assurances that significant costs and liabilities will not be incurred by the Company. Management is not aware of any contingent liabilities that currently exist with respect to environmental matters.

        Income Taxes—Provision for income taxes is attributable to the Company's state tax obligations under the gross margin tax enacted by the State of Texas. Since the Company is structured as a partnership for federal income tax purposes, the Company is not subject to federal income taxes. As a result, the Company's members are individually responsible for paying federal income taxes on their share of the Company's taxable income. See Note 9 for additional information regarding the Company's income taxes.

        Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

        Comprehensive Income (Loss)—Comprehensive income (loss) is the same as net income (loss) for all periods presented.

F-32

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Earnings Per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

        Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its consolidated financial statements.

        Unit Based Compensation—Certain of our current and former employees received Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC (collectively, the "Net Profits Interests"). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests are accounted for as compensatory awards. The Net Profits Interests vest ratably over four to five years, and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Company's Amended and Restated Limited Liability Operating Agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the Net Profits Interests as of the respective grant dates. The Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either the DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. See Note 10.

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM

        On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from TCEH (the "DFW Transaction"). At the date of the DFW Transaction, the Company received a capital contribution from Energy Capital Partners of $107,000 and contributed $85,082 to DFW Midstream in exchange for a 75% membership interest. Concurrently, DFW Midstream purchased certain natural gas gathering assets under construction located in the Barnett Shale from a division of Chesapeake Energy Corporation for $44,896, and a distribution of $40,186 was made by DFW Midstream to TCEH.

        The Company accounted for the DFW Transaction under the acquisition method of accounting, whereby the total purchase price of the DFW Transaction was allocated to DFW Midstream's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of September 3, 2009. The intangible assets acquired were right-of-way easements (weighted average life of 28.6 years) and favorable gas gathering agreements (weighted average life of 18.7 years). The intangible liabilities acquired were unfavorable gas gathering agreements. The fair values were

F-33

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete DFW Midstream's gathering system. The purchase price was estimated by imputing the value of 100% of the membership interests in DFW Midstream based upon $85,082 in cash contributed by Summit Midstream in exchange for an economic interest in DFW Midstream equal to 70.5% of future distributions and the obligation to contribute 75% of the project completion budget. The purchase price was equal to the fair value of the net assets of DFW Midstream; thus, no goodwill was recorded.

        Fair values of the assets acquired and liabilities assumed as of September 3, 2009 are as follows:

        In connection with the DFW Transaction, TCEH contributed assets consisting of property, plant and equipment related assets primarily under construction, gas gathering contracts and rights-of-way. The fair value of property, plant and equipment was determined utilizing the cost approach because of the early stage of construction or certain of the related assets having been recently purchased at the time of the DFW Transaction. The fair value of the gas gathering contracts was determined utilizing a discounted cash flow approach based upon the forecasted volumes under the applicable contract and the difference between the contractual and market rates for similar services in the area. The rights-of-way were valued based upon similar acreage and utilizing an assemblage factor for the contiguous easements acquired.

        The noncontrolling interest in DFW Midstream held by TCEH at September 3, 2009, was estimated based on TCEH's economic interest in DFW Midstream equal to 29.5% of future distributions and the obligation to contribute 25% of the capital expenditures in the project completion budget, and was adjusted to reflect the lack of control and lack of marketability that market participants would be expected to consider when estimating the fair value of the noncontrolling interest in DFW Midstream.

F-34

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

        In connection with the DFW Transaction, the Company incurred $3,921 in transaction costs, which were expensed as incurred and are reported within transaction costs. Such costs include $1,075 paid to Energy Capital Partners Management II, LP, a related party; $1,103 paid to Energy Capital Partners Management LP, a related party; and $1,743 paid to third parties (of which $1,603 was paid by Energy Capital Partners on behalf of the Company) for strategic, advisory, management, legal, and consulting services. Transaction costs paid by Energy Capital Partners are presented as a noncash capital contribution.

4. ACQUISITION OF GRAND RIVER GATHERING

        The Company completed the acquisition of Grand River Gathering from Encana for $590.2 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 260 miles of pipeline and approximately 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development.

        The Grand River Transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly-owned subsidiary of the Company. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million.

        The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised of gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete Grand River Gathering's gathering system. The Company completed the final purchase price allocation to the assets acquired and liabilities assumed during the second quarter of 2012 which has been recorded and presented on a retrospective basis and resulted in the recognition of $45.5 million of goodwill. Management believes the goodwill recorded upon the finalization of the allocation of the purchase price during the three months ended June 30, 2012 represents the incremental value of future cash flow potential attributed to estimated future gathering services within the emerging Mancos and Niobrara Shale developments.

F-35

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

        Fair values of the assets acquired and liabilities assumed as of October 27, 2011 are as follows:

        During the three months ended June 30, 2012, the acquired assets and assumed liabilities of Grand River Gathering were ultimately determined and the purchase price of the Grand River Transaction was finalized and concluded to be $590.2 million. Additionally, the Company also received the final information needed to value the acquired construction work in process and the intangible assets. As a result, the Company retrospectively recorded an adjustment to decrease its construction work in process by $4.7 million and decrease its intangible assets by $37.9 million based upon the final information received. The Company recorded $1.8 million of deferred revenue related to MVC payments received by the seller prior to the Company's purchase of the business which can be used by the producer to offset future gathering fees. Additionally, $0.9 million of the net working capital was recorded representing the final settlement of the remaining acquired assets and assumed liabilities of Grand River Gathering. These adjustments to the preliminary purchase price and the allocation to the assets acquired and liabilities assumed resulted in the recording of goodwill totaling $45.5 million. The Company also reduced the amortization expense on its acquired intangible assets by $548 from the previously reported amortization expense for the year ended December 31, 2011 as a result of the finalization of the intangible asset values.

        Unaudited Pro Forma Financial Information —The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010 and the DFW Midstream acquisition (see Note 3) occurred on January 1, 2009. Transaction costs of $3,160 related to the acquisition of Grand River Gathering have been adjusted and recorded in 2010 for the proforma information below. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the transactions had

F-36

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

occurred on those dates, or what the Company's financial position or results from operations will be for any future periods.

        Pro forma adjustments for the year ended December 31, 2011 consist of $64,119 of revenue and $13,294 of net income for January through October of 2011 and $76,943 of revenue and $15,953 for the year ended December 31, 2010 related to Grand River Gathering assuming the acquisition date was January 1, 2010. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that we recorded for the two month period from November 1, 2011 through December 31, 2011. The transaction costs of $3,160 have been removed from the year ended December 31, 2011 and reflected in the year ended December 31, 2010. Pro forma adjustments for the year ended December 31, 2009 represent $39 of revenue and $654 of depreciation related to DFW Midstream assuming the DFW Transaction was effective January 1, 2009.

        The unaudited pro forma financial information above was adjusted from the previously disclosed amounts in order to reflect the decrease in the values allocated to the intangible assets resulting from the finalization of the purchase price allocation which resulted in the unaudited pro forma net income to increase by $1,872 and $3,297 for the years ended December 31, 2011 and 2010.

F-37

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL

Identifiable Intangible Assets and Noncurrent Liability

        The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable intangible assets and a noncurrent liability, which are subject to amortization as of December 31, 2011 and 2010, are composed of the following:

        Amortization expense of $1,718, $764, $40, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

        Amortization expense of $1,862 for the year ended December 31, 2011 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in the depreciation and amortization expense in the statement of operations. The intangible asset contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

        Amortization expense of $908, $519, $114, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to rights-of-way associated with city

F-38

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL (Continued)

easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        The unfavorable contract included within noncurrent liability relates to an unfavorable gas gathering contract that was deemed to be below market upon the acquisition of DFW Midstream. Amortization related to the unfavorable gas gathering contract was $1,410, $549, $60, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within revenue. The unfavorable contract is amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

        The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from December 31, 2011 is as follows:

Goodwill

        The Company's goodwill of $45.5 million was recorded in connection with the Grand River Gathering acquisition in October 2011 which has all been allocated to the Company's Grand River Gathering reporting unit. Prior to the completion of this acquisition, the Company never had any goodwill recorded, and thus the Company has never recorded a goodwill impairment.

F-39

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

6. PROPERTY, PLANT, AND EQUIPMENT—NET

        Net property, plant, and equipment as of December 31, 2011 and 2010, is composed of the following:

        Depreciation expense related to property, plant, and equipment was $8,595, $3,355, $230, and $882 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively. The Company capitalized interest totaling $3,362 during the year ended December 31, 2011 and zero in any other period.

7. REVOLVING CREDIT FACILITY

        On May 26, 2011, Holdings closed a senior secured revolving credit facility with total commitments of $285 million. The revolving credit facility, which matures in May 2016, contains a $150 million accordion provision that enables Holdings to increase the total size of the facility any time prior to maturity. The revolving credit facility allows for revolving loans, letters of credit and swingline loans. The revolving credit facility is secured by the membership interests of Holdings and DFW Midstream and substantially all of Holdings' and DFW Midstream's assets and is guaranteed by Holdings' subsidiaries. Borrowings under the revolving credit facility bear interest at London Interbank Offered Rate ("LIBOR") plus an applicable margin or a base rate, as defined in the credit agreement. Under the terms of the revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at December 31, 2011. As of December 31, 2011, availability under the revolving credit facility totaled $138 million. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of December 31, 2011 was 2.88%.

        The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of December 31, 2011, Holdings was in compliance with all applicable covenants.

F-40

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

7. REVOLVING CREDIT FACILITY (Continued)

        The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners. As of December 31, 2011, there was $147 million outstanding under the facility.

        On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed $163 million under the facility. As of May 11, 2012, we had $307 million of indebtedness under our revolving credit facility. Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. The amended and restated revolving credit facility matures in May 2016.

8. PROMISSORY NOTES PAYABLE TO SPONSORS

        In conjunction with the purchase of Grand River Gathering, the Company executed promissory notes, on an unsecured basis, with its Sponsors. The notes totaled $200 million, mature on October 27, 2013 and have an 8% interest rate. The Company has the option to elect to pay the interest in kind and the Company made this election for all interest due as of December 31, 2011. The amount of interest paid in kind and accrued to the balance of the notes as December 31, 2011 is $2,893, resulting in $202,893 as the amount outstanding on the note as of December 31, 2011. During 2011, the Company capitalized $868 of the $2,893 interest expense related to costs incurred on capital projects under construction. As of December 31, 2011, the aggregate carrying value of these notes approximated the fair value. On May 7, 2012, the Company amended and restated its revolving credit facility. On May 8, 2012, the Company borrowed $163 million under the amended and restated revolving credit facility and used the same borrowings to prepay $160 million of the promissory notes payable to

F-41

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

8. PROMISSORY NOTES PAYABLE TO SPONSORS (Continued)

Sponsors. As of May 11, 2012, the balance under the promissory notes payable to Sponsors was $48,695.

9. INCOME TAXES

        In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $695, $124, $7, and $8, for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively.

10. MEMBERSHIP INTERESTS

        As described in Note 1, Summit Midstream is controlled by Energy Capital Partners through Energy Capital Partners' ownership of Class A membership interests in the Company. On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to GE Energy Financial Services, therefore as of December 31, 2011 Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. As of December 31, 2010 and 2009, Energy Capital Partners held all of the Company's membership interests. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

        In accordance with the Summit LLC Agreement, capital accounts are maintained for the Company's members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

        The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests described above.

F-42

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        Contemporaneously with the formation of Summit Midstream and the execution of the Summit LLC Agreement at September 3, 2009, Class B membership interests (the "SMP Net Profits Interests") up to 7.5% of Summit Midstream's total membership interests were authorized and 2.85% were granted to certain members of Summit Midstream Management, LLC. SMP Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested SMP Net Profits Interests. The SMP Net Profits Interests are accounted for as compensatory awards. Additional SMP Net Profits Interests were granted on April 1, 2010, April 1, 2011, and October 18, 2011. All grants vest ratably over 5 years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and Summit LLC Agreement). As of December 31, 2011, 5.855% of SMP Net Profits Interests had been granted, and no SMP Net Profits Interests had been forfeited.

        During the year ended December 31, 2011, the Company, with assistance from a third-party valuation expert, determined the fair value of the SMP Net Profits Interests as of the respective grant dates for the grants made prior to that date. Therefore, the 2011 awards were valued contemporaneously within the year issued, and the 2009 and 2010 awards were valued retrospectively. The SMP Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of Summit Midstream and considers the rights and preferences of each class of equity in order to allocate a fair value to each class.

        A significant input of the option pricing method is the enterprise value of the Company. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the Company. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the Company's peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the Company's estimated future cash flows.

        Additional significant inputs used in the option pricing method include length of holding period, discount for lack of marketability and volatility. The length of holding period was primarily determined based upon our Sponsors' expectations as of the grant date. The Company, with assistance from a third-party valuation firm, estimated the discount for lack of marketability and volatility. The discount for lack of marketability was estimated using a protective put methodology. The protective put methodology consisted of estimating the cost to insure an investment in the SMP Net Profits Interests over the length of the holding period. Using the Black-Scholes option pricing model, we calculated the cost of a put option for the SMP Net Profits Interests as of the various grant dates. The discount for lack of marketability, in each case, is equal to the put option value divided by the value of the underlying membership interest. We estimated the expected volatility of the SMP Net Profits Interests

F-43

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

based on the historical and implied volatilities of the securities of publicly-traded peer companies. We estimated historical volatility based on daily stock price returns over a look-back period commensurate with the length of the holding period for each grant of SMP Net Profits Interests. We estimated implied volatility based on the average implied volatility of the publicly-traded peer companies using data from Standard & Poor's Capital IQ proprietary research tool. The expected volatility conclusions were based on consideration of both the historical and implied volatilities of the publicly-traded peer companies as of the various grant dates. These inputs used in the option pricing method for the SMP Net Profits granted in each of the years designated below are as follows:

        Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests as of December 31, 2009, 2010, and 2011 is presented below.

F-44

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        The Company recognizes compensation expense ratably over the five year vesting period. The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $1,269 which included $463 related to years prior to 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 3.2 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $3,971.

        In connection with the Company's formation and acquisition of DFW Midstream on September 3, 2009, Energy Capital Partners contributed $107,000 to the Company in order to initially capitalize the Company and fund the Company's investment in DFW Midstream. Energy Capital Partners contributed an additional $27,871 of capital to Summit Midstream through December 31, 2009. Energy Capital Partners made cash contributions of $194,134 to the Company for the year ended December 31, 2010, which were primarily used to fund ongoing capital expenditures of DFW Midstream and purchase the remaining noncontrolling interest in DFW Midstream from TCEH on June 18, 2010, as discussed below.

        In connection with the closing of the Company's revolving credit facility in May 2011, the Company distributed $132,943 to Energy Capital Partners.

        Noncontrolling Interest in DFW Midstream—During the three years ended December 31, 2011, the Company has had several changes in membership interests related to the ownership of its consolidated subsidiary DFW Midstream as discussed further below. At December 31, 2011 and 2010, 100% of the Class A membership interests of DFW Midstream were held by Summit Midstream or its direct subsidiary, Holdings. Summit Midstream, through its subsidiary Holdings, as the sole Class A Member, holds units that represent membership interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement (collectively the "LLC Agreement"). The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive.

        In accordance with the LLC Agreement, capital accounts are maintained for the members. The capital account provisions of the LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

        The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive. Prior to Summit's purchase of TCEH's remaining interest in DFW Midstream on June 18, 2010 (as discussed immediately below), Summit held a 75% interest and TCEH held a 25% Class A membership interest; however, distributions and allocations of income and loss are based on a sharing percentage as defined in the LLC Agreement resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit and TCEH,

F-45

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

respectively. Capital contributions required under the LLC Agreement are in proportion to the owners' respective percentage ownership interests.

        In 2010, Summit Midstream and TCEH entered into a Membership Interest Purchase Agreement whereby Summit Midstream purchased all of TCEH's membership interests in DFW Midstream for cash consideration of $90,722. Amounts reported as noncontrolling interest relate to TCEH's ownership interests in DFW Midstream prior to June 18, 2010. The change in Summit Midstream's ownership interest in DFW Midstream resulted in a decrease in membership interest of $25,126 for the year ended December 31, 2010, as the cash consideration paid exceeded the carrying value of the noncontrolling interest at June 18, 2010.

        Distributions and allocations of income and loss for the periods presented prior to June 18, 2010, are based upon a sharing percentage as defined in the Amended and Restated LLC Agreement of DFW Midstream resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit Midstream and TCEH, respectively. Net income (loss) of $78 and $(400) was allocated to TCEH, as the noncontrolling interest holder, based upon its ownership interests and profits and losses allocation for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively.

        TCEH funded capital contributions in the amount of $10,720 and $15,417 for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively. Additionally, in connection with the Company's acquisition of DFW Midstream on September 3, 2009, DFW Midstream distributed $40,186 to TCEH as a return of capital.

        Contemporaneously with the execution of the LLC Agreement on September 3, 2009, up to 5% of DFW Midstream's total membership interests were authorized for issuance as Class B membership interests (the "DFW Net Profits Interests) and an aggregate of 4.50% of DFW Net Profits Interests were granted to certain members of DFW Midstream Management LLC. DFW Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. Additional DFW Net Profits Interests were granted on April 1, 2010 and July 28, 2010. All grants vest ratably over 4 years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and LLC Agreement). As of December 31, 2011, 4.80% of DFW Net Profits Interests had been granted and 0.40% DFW Net Profits Interests had been forfeited.

        During the year ended December 31, 2011, the Company, with assistance from a third-party valuation expert, determined the fair value of the DFW Net Profits Interests as of the respective grant dates for the grants made prior to that date. Therefore, the 2009 and 2010 awards were valued retrospectively. The DFW Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of

F-46

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

DFW Midstream and considers the rights and preferences of each class of equity in order to allocate a fair value to each class.

        A significant input of the option pricing method is the enterprise value of DFW Midstream. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the DFW Midstream. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the DFW Midstream peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the DFW Midstream's estimated future cash flows.

        Additional significant inputs used in the option pricing method include the length of holding period, discount for lack of marketability and volatility. The length of holding period was determined primarily based on our Sponsors' expectations as of the grant date. The Company, with assistance from a third-party valuation firm, estimated the discount for lack of marketability and volatility. The discount for lack of marketability was estimated using a protective put methodology. The protective put methodology consisted of estimating the cost to insure an investment in the SMP Net Profits Interests over the length of the holding period. Using the Black-Scholes option pricing model, we calculated the cost of a put option for the DFW Net Profits Interests as of the various grant dates. The discount for lack of marketability, in each case, is equal to the put option value divided by the value of the underlying membership interest. We estimated the expected volatility of the DFW Net Profits Interests based on the historical and implied volatilities of the securities of publicly-traded peer companies. We estimated historical volatility based on daily stock price returns over a look-back period commensurate with the length of the holding period for each grant date DFW Net Profits Interests. We estimated implied volatility based on the average implied volatility of the publicly-traded peer companies using data from Standard & Poor's Capital IQ proprietary research tool. The expected volatility conclusions are based on consideration of both the historical and implied volatilities for the publicly-traded peer companies as of the various grant dates. These inputs used in the option pricing method for the DFW Net Profits granted in each of the years designated below are as follows:

F-47

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        Information regarding the amount and grant-date fair value of the vested and nonvested DFW Net Profits Interests as of December 31, 2009, 2010, and 2011 is presented below.

F-48

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        The Company recognizes compensation expense ratably over the four year vesting period. The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $2,171 which included $582 related to years prior to 2011. During the year ended December 31, 2011, the Company modified the awards to remove a rate of return payout hurdle and as a result of the modification; the Company valued the Class B Units immediately prior to and following the modification to determine incremental compensation expense. The modification resulted in the immediate expense of $1,358 attributed to the previously vested Class B Units which is included in the $1,589 of compensation expense recorded during the year ended December 31, 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 2.1 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $1,321.

        Predecessor Membership Interests—Prior to the DFW Transaction, TCEH funded the Company's construction activities and working capital needs through intercompany loans or advances that accrued interest at an average rate of 4.29% for the predecessor period. Immediately prior to the DFW Transaction, the advances were converted to a membership interest.

11. COMMITMENTS AND CONTINGENCIES

        Contractual Commitments—The Company leases office space for its headquarters in Dallas, Texas and for other offices in Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas , and has determined that its leases are classified as operating leases. A schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011 is as follows:

        Total rent expense related to operating leases was $489, $212, $28, and $0 for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) to December 31, 2009, the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within general and administrative.

        Legal Proceedings—The Company is involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on the Company's financial condition, results of operations, or liquidity.

F-49

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. RELATED-PARTY TRANSACTIONS

        Transaction Costs—As discussed in Note 3, during 2009 the Company paid transaction costs of $1,075 and $1,103 to Energy Capital Partners Management II, LP and Energy Capital Partners Management, LP, respectively.

        Diligence Expenses—The Sponsors agreed to reimburse the Company for previous transactional due diligence expenses related to proposed transactions that were not completed. As of December 31, 2011, the Company had a receivable from the Sponsors of $1,309 related to this previous agreement.

        Transition Services Agreement—The Company executed a transition services agreement with TCEH effective September 3, 2009. The services provided to the Company by TCEH included the temporary use of TCEH office space; ongoing utilization of accounting and financial reporting services support; general support regarding any administration of Consolidated Omnibus Budget Reconciliation Act (COBRA) health benefits; general information technology support to manage data files, addresses, network connectivity, etc.; and use of computers, right-of-way services, and public relation services. The costs and rates charged to the Company by TCEH related to each service were negotiated and mutually agreed to by both parties. The termination date related to each service provided under the agreement varies with the option to extend certain services if deemed necessary and agreed to by both parties. The extension periods are in three-month intervals beginning January 1, 2010, and are limited to 18 months in total. As of December 31, 2011, the only services provided under the agreement that remain relate to the right-of-way services. The amounts charged to the Company through the transition services agreement for the years ended December 31, 2011 and 2010 and for the period from September 3, 2009 (inception) through December 31, 2009, were $39, $137 and $100, respectively.

        Promissory Notes—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 8)

        Electricity Management Services Agreement—The Company entered into a consulting arrangement with EquiPower Resources Corp. ("EquiPower"), an affiliate of Energy Capital Partners, whereby EquiPower assists the Company with managing its electricity price risk. During the years ended December 31, 2011 and 2010, the Company paid EquiPower $11 and zero for such services, respectively.

13. CONCENTRATIONS OF RISK

        Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and accounts receivable. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.

        Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale of natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the Company's

F-50

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

13. CONCENTRATIONS OF RISK (Continued)

customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

        For the years ended December 31, 2011 and 2010, the Company had four customers (each comprising over 10% of total revenue) that accounted for approximately 73% and 88% of total gas revenue, respectively. The total accounts receivable from these customers accounted for approximately 66% and 95% of accounts receivable for the years ended December 31, 2011 and 2010, respectively.

        The following tables summarize concentrations of revenue and accounts receivable in excess of 10% of total revenue and accounts receivable as of and for the years ended December 31, 2011 and 2010, for the period from September 3, 2009 (inception) through December 31, 2009 and for the period from January 1, 2009 through September 3, 2009, respectively:

******

F-51

---

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC as general partner of Summit Midstream Partners, LP
Dallas, Texas

        We have audited the accompanying balance sheet of Summit Midstream Partners, LP (the "Partnership") as of May 10, 2012. The balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on the balance sheet based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Partnership as of May 10, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-52

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP

BALANCE SHEET

MAY 10, 2012

F-53

---

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP

NOTE TO BALANCE SHEET

1. Nature of Operations

        Summit Midstream Partners, LP (the "Partnership") is a Delaware limited partnership formed on May 1, 2012 to acquire certain assets and related contracts and agreements from the operating subsidiaries of Summit Midstream Partners, LLC. In order to simplify the Partnership's obligations under the laws of selected jurisdictions in which the Partnership will conduct business, the Partnership's activities will be conducted through a wholly owned limited liability company.

        Summit Midstream GP, LLC, as general partner, contributed $20 and Summit Midstream Partners, LLC, as the organizational limited partner, contributed $980 to the Partnership on May 10, 2012.

2. Summary of Significant Accounting Policies

Basis of Presentation

        This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America. Separate statements of operations, membership interests, and cash flows have not been presented because the entity has had no business transactions or activities to date.

Subsequent Events

        Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

3. Commitments and Contingencies

        As of the date of these financial statements, Summit Midstream Partners, LP had no outstanding commitments and contingencies.

F-54

---

Table of Contents

APPENDIX A
FIRST AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
SUMMIT MIDSTREAM PARTNERS, LP
A Delaware Limited Partnership
Dated as of
, 2012

---

Table of Contents

TABLE OF CONTENTS

A-i

---

Table of Contents

A-ii

---

Table of Contents

A-iii

---

Table of Contents

FIRST AMENDED AND RESTATED AGREEMENT OF
LIMITED PARTNERSHIP OF SUMMIT MIDSTREAM PARTNERS, LP

        THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF SUMMIT MIDSTREAM PARTNERS, LP dated as of                        , 2012, is entered into by and between Summit Midstream GP, LLC, a Delaware limited liability company, as the General Partner, and Summit Midstream Partners, LLC, a Delaware limited liability company, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I.
DEFINITIONS

        Section 1.1    Definitions.     The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

        "Acquisition" means any transaction in which any Group Member acquires (through an asset acquisition, stock acquisition, merger or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing, over the long-term, the operating capacity or operating income of the Partnership Group from the operating capacity or operating income of the Partnership Group existing immediately prior to such transaction. For purposes of this definition, "long-term" generally refers to a period of not less than twelve months.

        "Additional Book Basis" means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

        (a)   Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event; and

        (b)   If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership's Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

        "Additional Book Basis Derivative Items" means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership's Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the "Excess Additional Book Basis"), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis

A-1

---

Table of Contents

taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property.

        "Adjusted Capital Account" means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such taxable period, are reasonably expected to be allocated to such Partner in subsequent taxable periods under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such taxable period, are reasonably expected to be made to such Partner in subsequent taxable periods in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner's Capital Account that are reasonably expected to occur during (or prior to) the taxable period in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The "Adjusted Capital Account" of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

        "Adjusted Operating Surplus" means, with respect to any period, (a) Operating Surplus generated with respect to such period less (b) (i) the amount of any net increase in Working Capital Borrowings (or the Partnership's proportionate share of any net increase in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to such period and (ii) the amount of any net decrease in cash reserves (or the Partnership's proportionate share of any net decrease in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and plus (c) (i) the amount of any net decrease in Working Capital Borrowings (or the Partnership's proportionate share of any net decrease in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to such period, (ii) the amount of any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above and (iii) the amount of any net increase in cash reserves (or the Partnership's proportionate share of any net increase in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of "Operating Surplus."

        "Adjusted Property" means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d).

        "Affiliate" means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

        "Aggregate Quantity of IDR Reset Common Units" has the meaning given such term in Section 5.11(a).

        "Aggregate Remaining Net Positive Adjustments" means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

A-2

---

Table of Contents

        "Agreed Allocation" means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate in the context in which the term "Agreed Allocation" is used).

        "Agreed Value" of any Contributed Property means the fair market value of such property or other consideration at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.5(d), in both cases as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

        "Agreement" means this First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, as it may be amended, supplemented or restated from time to time.

        "Associate" means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest, (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity, and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

        "Available Cash" means, with respect to any Quarter ending prior to the Liquidation Date:

        (a)   the sum of:

          (i)  all cash and cash equivalents of the Partnership Group (or the Partnership's proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter; and

         (ii)  if the General Partner so determines, all or any portion of additional cash and cash equivalents of the Partnership Group (or the Partnership's proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter; less

        (b)   the amount of any cash reserves established by the General Partner (or the Partnership's proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to:

          (i)  provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter;

         (ii)  comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

        (iii)  provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters;

provided, however, that the General Partner may not establish cash reserves pursuant to subclause (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to

A-3

---

Table of Contents

have been made, established, increased or reduced, for purposes of determining Available Cash within such Quarter if the General Partner so determines.

        Notwithstanding the foregoing, "Available Cash" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

        "Board of Directors" means, with respect to the General Partner, its board of directors or board of managers, if the General Partner is a corporation or limited liability company, or the board of directors or board of managers of the general partner of the General Partner, if the General Partner is a limited partnership, as applicable.

        "Book Basis Derivative Items" means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

        "Book-Down Event" means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

        "Book-Tax Disparity" means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner's share of the Partnership's Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner's Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner's Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

        "Book-Up Event" means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

        "Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Delaware shall not be regarded as a Business Day.

        "Capital Account" means the capital account maintained for a Partner pursuant to Section 5.5. The "Capital Account" of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

        "Capital Contribution" means (a) any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions) or (b) current distributions that a Partner is entitled to receive but otherwise waives.

        "Capital Improvement" means (a) the construction of new capital assets by a Group Member, (b) the replacement, improvement or expansion of existing capital assets by a Group Member or (c) a capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has, or after such capital contribution will have, directly or indirectly, an equity interest, to fund such Group Member's pro rata share of the cost of the construction of new, or the replacement, improvement or expansion of existing, capital assets by such Person, in each case if and to the extent such construction, replacement, improvement or expansion is made to increase, over the long-term, the operating capacity or operating income of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the operating capacity or operating income of the Partnership Group or such Person, as the case may be, existing immediately prior to such construction,

A-4

---

Table of Contents

replacement, improvement, expansion or capital contribution. For purposes of this definition, "long-term" generally refers to a period of not less than twelve months.

        "Capital Surplus" means Available Cash distributed by the Partnership in excess of Operating Surplus, as described in Section 6.3(a).

        "Carrying Value" means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners' Capital Accounts in respect of such property and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination; provided that the Carrying Value of any property shall be adjusted from time to time in accordance with Sections 5.5(d)(i) and 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

        "Cause" means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

        "Certificate" means a certificate in such form (including global form if permitted by applicable rules and regulations of the Depository Trust Company and its permitted successors and assigns) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more classes of Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

        "Certificate of Limited Partnership" means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

        "Citizenship Eligible Holder" means a Limited Partner whose nationality, citizenship or other related status the General Partner determines, upon receipt of an Eligibility Certificate or other requested information, does not or would not create under any federal, state or local law or regulation to which a Group Member is subject, a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which a Group Member has an interest.

        "Claim" (as used in Section 7.12(g)) has the meaning given such term in Section 7.12(g).

        "Closing Date" means the first date on which Common Units are sold by the Partnership to the IPO Underwriters pursuant to the provisions of the IPO Underwriting Agreement.

        "Closing Price" for any day, means, in respect of any class of Limited Partner Interest, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the last closing bid and ask prices on such day, regular way, in either case as reported on the principal National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the average of the high bid and low ask prices on such day in the over-the-counter market, as reported by such other system then in use, or, if on any such day such Limited Partner Interests are not quoted by any such organization, the average of the closing bid and ask prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

A-5

---

Table of Contents

        "Code" means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

        "Combined Interest" has the meaning given such term in Section 11.3(a).

        "Commences Commercial Service" means the date upon which a Capital Improvement is first put into commercial service by a Group Member following completion of construction, replacement, improvement or expansion and testing, as applicable.

        "Commission" means the United States Securities and Exchange Commission.

        "Common Unit" means a Limited Partner Interest having the rights and obligations specified with respect to Common Units in this Agreement. The term "Common Unit" does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

        "Common Unit Arrearage" means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

        "Conflicts Committee" means a committee of the Board of Directors of the General Partner composed of one or more directors, each of whom (a) is not an officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner (other than Group Members), (c) is not a holder of any ownership interest in the General Partner or its Affiliates or the Partnership Group other than (i) Common Units and (ii) awards that are granted to such director in his capacity as a director under any long-term incentive plan, equity compensation plan or similar plan implemented by the General Partner or the Partnership and (d) is determined by the Board of Directors of the General Partner to be independent under the independence standards for directors who serve on an audit committee of a board of directors established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading (or if no such National Securities Exchange, the New York Stock Exchange).

        "Construction Debt" means debt incurred to fund (a) all or a portion of a Capital Improvement, (b) interest payments (including periodic net payments under related interest rate swap agreements) and related fees on other Construction Debt or (c) distributions (including incremental Incentive Distributions) on Construction Equity.

        "Construction Equity" means equity issued to fund (a) all or a portion of a Capital Improvement, (b) interest payments (including periodic net payments under related interest rate swap agreements) and related fees on Construction Debt or (c) distributions (including incremental Incentive Distributions) on other Construction Equity. Construction Equity does not include equity issued in the Initial Public Offering.

        "Construction Period" means the period beginning on the date that a Group Member enters into a binding obligation to commence a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that the Group Member abandons or disposes of such Capital Improvement.

        "Contributed Property" means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property or other asset shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

A-6

---

Table of Contents

        "Contribution Agreement" means that certain Contribution, Conveyance and Assumption Agreement, dated as of , 2012, among the Partnership, the General Partner, Summit Midstream Partners, LLC and the Operating Company, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

        "Cumulative Common Unit Arrearage" means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum of the Common Unit Arrearages as to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

        "Curative Allocation" means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

        "Current Market Price" as of any date of any class of Limited Partner Interests, means the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

        "Delaware Act" means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

        "Departing General Partner" means a former general partner from and after the effective date of any withdrawal or removal of such former general partner pursuant to Section 11.1 or Section 11.2.

        "Derivative Partnership Interests" means any options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative securities relating to, convertible into or exchangeable for Partnership Interests.

        "Disposed of Adjusted Property" has the meaning given such term in Section 6.1(d)(xii)(B).

        "Economic Risk of Loss" has the meaning set forth in Treasury Regulation Section 1.752-2(a).

        "Eligibility Certificate" means a certificate the General Partner may request a Limited Partner to execute as to such Limited Partner's (or such Limited Partner's beneficial owners') federal income tax status or nationality, citizenship or other related status for the purpose of determining whether such Limited Partner is an Ineligible Holder.

        "Estimated Incremental Quarterly Tax Amount" has the meaning given to such term in Section 6.9.

        "Event of Withdrawal" has the meaning given such term in Section 11.1(a).

        "Excess Additional Book Basis" has the meaning given such term in the definition of "Additional Book Basis Derivative Items."

        "Excess Distribution" has the meaning given such term in Section 6.1(d)(iii)(A).

        "Excess Distribution Unit" has the meaning given such term in Section 6.1(d)(iii)(A).

        "Exchange Act" means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute.

        "Expansion Capital Expenditures" means cash expenditures for Acquisitions or Capital Improvements. Expansion Capital Expenditures shall include interest (including periodic net payments under related interest rate swap agreements) and related fees paid during the Construction Period on Construction Debt. Where cash expenditures are made in part for Expansion Capital Expenditures and

A-7

---

Table of Contents

in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

        "FERC" means the U.S. Federal Energy Regulatory Commission.

        "Final Subordinated Units" has the meaning given such term in Section 6.1(d)(x)(A).

        "First Liquidation Target Amount" has the meaning given such term in Section 6.1(c)(i)(D).

        "First Target Distribution" means $[            ] per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on                        , 2012, it means the product of $[            ] multiplied by a fraction of which the numerator is the number of days in such period, and of which the denominator is 92), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

        "Fully Diluted Weighted Average Basis" means, when calculating the number of Outstanding Units for any period, a basis that includes (a) the weighted average number of Outstanding Units during such period plus (b) all Partnership Interests and Derivative Partnership Interests (i) that are convertible into or exercisable or exchangeable for Units or for which Units are issuable, in each case that are senior to or pari passu with the Subordinated Units, (ii) whose conversion, exercise or exchange price, if any, is less than the Current Market Price on the date of such calculation, (iii) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (iv) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Weighted Average Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Interests and Derivative Partnership Interests shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (x) the number of Units issuable upon such conversion, exercise or exchange and (y) the number of Units that such consideration would purchase at the Current Market Price.

        "General Partner" means Summit Midstream GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

        "General Partner Interest" means the interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

        "General Partner Unit" means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit shall not constitute a "Unit" for any purpose under this Agreement.

        "Gross Liability Value" means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm's-length transaction.

A-8

---

Table of Contents

        "Group" means two or more Persons that with or through any of their respective Affiliates or Associates have any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power over or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

        "Group Member" means a member of the Partnership Group.

        "Group Member Agreement" means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, in each case as such may be amended, supplemented or restated from time to time.

        "Hedge Contract" means any exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of a Group Member to fluctuations in interest rates, the price of hydrocarbons, basis differentials or currency exchange rates in their operations or financing activities and not for speculative purposes.

        "Holder" means any of the following:

        (a)   the General Partner who is the Record Holder of Registrable Securities;

        (b)   any Affiliate of the General Partner who is the Record Holder of Registrable Securities (other than natural persons who are Affiliates of the General Partner by virtue of being officers, directors or employees of the General Partner or any of its Affiliates);

        (c)   any Person who has been the General Partner within the prior two years and who is the Record Holder of Registrable Securities;

        (d)   any Person who has been an Affiliate of the General Partner within the prior two years and who is the Record Holder of Registrable Securities (other than natural persons who were Affiliates of the General Partner by virtue of being officers, directors or employees of the General Partner or any of its Affiliates); and

        (e)   a transferee and current Record Holder of Registrable Securities to whom the transferor of such Registrable Securities, who was a Holder at the time of such transfer, assigns its rights and obligations under this Agreement; provided such transferee agrees to comply with all applicable requirements and obligations in connection with the registration and disposition of such Registrable Securities pursuant to Section 7.12.

        "IDR Reset Common Units" has the meaning given such term in Section 5.11(a).

        "IDR Reset Election" has the meaning given such term in Section 5.11(a).

        "Incentive Distribution Right" means a Limited Partner Interest having the rights and obligations specified with respect to Incentive Distribution Rights in this Agreement (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest).

        "Incentive Distributions" means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Sections 6.4(a)(v), (vi) and (vii) and 6.4(b)(iii), (iv) and (v).

        "Incremental Income Taxes" has the meaning given such term in Section 6.9.

A-9

---

Table of Contents

        "Indemnified Persons" has the meaning given such term in Section 7.12(g).

        "Indemnitee" means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of (i) any Group Member, the General Partner or any Departing General Partner or (ii) any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a manager, managing member, general partner, director, officer, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an "Indemnitee" for purposes of this Agreement because such Person's status, service or relationship exposes such Person to potential claims, demands, suits or proceedings relating to the Partnership Group's business and affairs.

        "Ineligible Holder" means a Limited Partner who is not a Citizenship Eligible Holder or a Rate Eligible Holder.

        "Initial Common Units" means the Common Units sold in the Initial Public Offering.

        "Initial Limited Partners" means Organizational Limited Partner, the General Partner (with respect to the Incentive Distribution Rights received by it pursuant to Section 5.3(a)) and the IPO Underwriters upon the issuance by the Partnership of Common Units as described in Section 5.3(b) in connection with the Initial Public Offering.

        "Initial Public Offering" means the initial offering and sale of Common Units to the public (including the offer and sale of Common Units pursuant to the Over-Allotment Option), as described in the IPO Registration Statement.

        "Initial Unit Price" means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Common Units were first offered to the public for sale as set forth on the cover page of the IPO Prospectus or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

        "Interim Capital Transactions" means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) issuances of equity interests of any Group Member (including the Common Units sold to the IPO Underwriters in the Initial Public Offering); (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and (ii) sales or other dispositions of assets as part of normal retirements or replacements; and (d) capital contributions received by a Group Member.

        "IPO Prospectus" means the final prospectus relating to the Initial Public Offering dated [            ] and filed by the Partnership with the Commission pursuant to Rule 424 on [            ].

        "IPO Registration Statement" means the Registration Statement on Form S-1 (File No. 333-                        ) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Public Offering.

A-10

---

Table of Contents

        "IPO Underwriter" means each Person named as an underwriter in Schedule I to the IPO Underwriting Agreement who purchases Common Units pursuant thereto.

        "IPO Underwriting Agreement" means that certain Underwriting Agreement dated as of                        , 2012 among the IPO Underwriters, Summit Midstream Partners, LLC, the Partnership, the General Partner and the Operating Company providing for the purchase of Common Units by the IPO Underwriters.

        "Liability" means any liability or obligation of any nature, whether accrued, contingent or otherwise.

        "Limited Partner" means, unless the context otherwise requires each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person's capacity as a limited partner of the Partnership.

        "Limited Partner Interest" means an interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof (but excluding Derivative Partnership Interests), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner pursuant to the terms and provisions of this Agreement.

        "Liquidation Date" means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

        "Liquidator" means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

        "Maintenance Capital Expenditures" means cash expenditures (including expenditures for the construction of new capital assets or the replacement, improvement or expansion of existing capital assets) by a Group Member made to maintain, over the long term, the operating capacity or operating income of the Partnership Group. For purposes of this definition, "long term" generally refers to a period of not less than twelve months.

        "Merger Agreement" has the meaning given such term in Section 14.1.

        "Minimum Quarterly Distribution" means $[            ] per Unit per Quarter (or with respect to the period commencing on the Closing Date and ending on                        , 2012, it means the product of $ [            ] multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

        "National Securities Exchange" means an exchange registered with the Commission under Section 6(a) of the Exchange Act (or any successor to such Section).

        "Net Agreed Value" means, (a) in the case of any Contributed Property, the Agreed Value of such property or other consideration reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property or other consideration is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership's Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such

A-11

---

Table of Contents

property is subject at the time of distribution, in either case as determined and required by the Treasury Regulations promulgated under Section 704(b) of the Code.

        "Net Income" means, for any taxable period, the excess, if any, of the Partnership's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

        "Net Loss" means, for any taxable period, the excess, if any, of the Partnership's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

        "Net Positive Adjustments" means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

        "Net Termination Gain" means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized by the Partnership pursuant to Section 5.5(d); provided, however, the items included in the determination of Net Termination Gain shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

        "Net Termination Loss" means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized by the Partnership pursuant to Section 5.5(b); provided, however, items included in the determination of Net Termination Loss shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

        "Nonrecourse Built-in Gain" means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

        "Nonrecourse Deductions" means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

        "Nonrecourse Liability" has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

A-12

---

Table of Contents

        "Notice" means a written request from a Holder pursuant to Section 7.12 which shall (i) specify the Registrable Securities intended to be registered, offered and sold by such Holder, (ii) describe the nature or method of the proposed offer and sale of Registrable Securities, and (iii) contain the undertaking of such Holder to provide all such information and materials and take all action as may be required or appropriate in order to permit the Partnership to comply with all applicable requirements and obligations in connection with the registration and disposition of such Registrable Securities pursuant to Section 7.12.

        "Notice of Election to Purchase" has the meaning given such term in Section 15.1(b).

        "Operating Company" means Summit Midstream Holdings, LLC, a Delaware limited liability company, and any successors thereto.

        "Operating Expenditures" means all Partnership Group cash expenditures (or the Partnership's proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes, compensation of employees, officers and directors of the General Partner, reimbursement of expenses of the General Partner and its Affiliates, Maintenance Capital Expenditures, debt service payments, repayment of Working Capital Borrowings, and payments made in the ordinary course of business under any Hedge Contracts, subject to the following:

        (a)   repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid;

        (b)   payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures;

        (c)   Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (iii) distributions to Partners, (iv) repurchases of Partnership Interests, other than repurchases of Partnership Interests by the Partnership to satisfy obligations under employee benefit plans or reimbursement of expenses of the General Partner for purchases of Partnership Interests by the General Partner to satisfy obligations under employee benefit plans, or (v) any other expenditures or payments using the proceeds of the Initial Public Offering as described under "Use of Proceeds" in the IPO Registration Statement; and

        (d)   (i) amounts paid in connection with the initial purchase of a Hedge Contract shall be amortized as Operating Expenditures over the life of such Hedge Contract and (ii) payments made in connection with the termination of any Hedge Contract prior to the expiration of its scheduled settlement or termination date shall be included as Operating Expenditures in equal quarterly installments over the remaining scheduled life of such Hedge Contract.

        "Operating Surplus" means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

        (a)   the sum of (i) $[            ] million, (ii) all cash receipts of the Partnership Group (or the Partnership's proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions and the termination of Hedge Contracts (provided that cash receipts from the termination of a Hedge Contract prior to its scheduled settlement or termination date shall be included in Operating Surplus in equal quarterly installments over the remaining scheduled life of such Hedge Contract), (iii) all cash receipts of the Partnership Group (or the Partnership's proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus

A-13

---

Table of Contents

with respect to such period resulting from Working Capital Borrowings and (iv) the amount of cash distributions from Operating Surplus paid during the Construction Period (including incremental Incentive Distributions) on Construction Equity, less

        (b)   the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period, (ii) the amount of cash reserves (or the Partnership's proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner to provide funds for future Operating Expenditures, and (iii) all Working Capital Borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional Working Capital Borrowings; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, "Operating Surplus" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

        "Opinion of Counsel" means a written opinion of counsel (who may be regular counsel to, or the general counsel or other inside counsel of, the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner or to such other person selecting such counsel or obtaining such opinion.

        "Option Closing Date" means the date or dates on which any Common Units are sold by the Partnership to the IPO Underwriters upon exercise of the Over-Allotment Option.

        "Organizational Limited Partner" means Summit Midstream Partners, LLC in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

        "Outstanding" means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership's books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class, all Partnership Interests owned by or for the benefit of such Person or Group shall not be entitled to be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that, upon or prior to such acquisition, the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership with the prior approval of the Board of Directors of the General Partner.

        "Over-Allotment Option" means the over-allotment option granted to the IPO Underwriters by the Partnership pursuant to the IPO Underwriting Agreement.

        "Partner Nonrecourse Debt" has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

A-14

---

Table of Contents

        "Partner Nonrecourse Debt Minimum Gain" has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

        "Partner Nonrecourse Deductions" means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

        "Partners" means the General Partner and the Limited Partners.

        "Partnership" means Summit Midstream Partners, LP, a Delaware limited partnership.

        "Partnership Group" means, collectively, the Partnership and its Subsidiaries.

        "Partnership Interest" means any equity interest, including any class or series of any equity interest, in the Partnership, which shall include any Limited Partner Interests and the General Partner Interest but shall exclude any Derivative Partnership Interests.

        "Partnership Minimum Gain" means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

        "Partnership Register" means a register maintained on behalf of the Partnership by the General Partner, or, if the General Partner so determines, by the Transfer Agent as part of the Transfer Agent's books and transfer records, with respect to each class of Partnership Interests in which all Record Holders and transfers of such class of Partnership Interests are registered or otherwise recorded.

        "Per Unit Capital Amount" means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

        "Percentage Interest" means as of any date of determination (a) as to the General Partner with respect to General Partner Units and as to any Unitholder with respect to Units, as the case may be, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and General Partner Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

        "Person" means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

        "Plan of Conversion" has the meaning given such term in Section 14.1.

        "Pro Rata" means (a) when used with respect to Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests, (c) when used with respect to holders of Incentive Distribution Rights, apportioned among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder, and (d) when used with respect to Holders who have requested to include Registrable Securities in a Registration Statement pursuant to Section 7.12(a) or 7.12(b), apportioned among all such Holders in accordance with the relative number of Registrable Securities held by each such holder and included in the Notice relating to such request.

A-15

---

Table of Contents

        "Purchase Date" means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

        "Quarter" means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership which includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

        "Rate Eligible Holder" means a Limited Partner subject to United States federal income taxation on the income generated by the Partnership. A Limited Partner that is an entity not subject to United States federal income taxation on the income generated by the Partnership shall be deemed a Rate Eligible Holder so long as all of the entity's beneficial owners are subject to such taxation.

        "Recapture Income" means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

        "Record Date" means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to receive notice of, or entitled to exercise rights in respect of, any lawful action of Limited Partners (including voting) or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

        "Record Holder" means (a) with respect to any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the Partnership's close of business on a particular Business Day or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the Partnership's close of business on a particular Business Day.

        "Redeemable Interests" means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

        "Registrable Security" means any Partnership Interests other than the General Partner Interest and General Partner Units; provided that any Registrable Security shall cease to be a Registrable Security (a) at the time a Registration Statement covering such Registrable Security is declared effective by the Commission or otherwise becomes effective under the Securities Act, and such Registrable Security has been sold or disposed of pursuant to such Registration Statement; (b) at the time such Registrable Security has been disposed of pursuant to Rule 144 (or any successor or similar rule or regulation under the Securities Act); (c) when such Registrable Security is held by a Group Member; and (d) at the time such Registrable Security has been sold in a private transaction in which the transferor's rights under Section 7.12 of this Agreement have not been assigned to the transferee of such securities.

        "Registration Statement" has the meaning given such term in Section 7.12(a).

        "Remaining Net Positive Adjustments" means as of the end of any taxable period, (a) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (i) the Net Positive Adjustments of the Unitholders holding Common Units or Subordinated Units as of the end of such period over (ii) the sum of those Partners' Share of Additional Book Basis Derivative Items for each prior taxable period, (b) with respect to the General Partner (as holder of the General Partner Units), the excess of (i) the Net Positive Adjustments of the General Partner as of the end of such period over (ii) the sum of the General Partner's Share of Additional Book Basis Derivative Items with respect to the General Partner Units for each prior taxable period, and (c) with respect to the holders of

A-16

---

Table of Contents

Incentive Distribution Rights, the excess of (i) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (ii) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

        "Required Allocations" means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii) or Section 6.1(d)(ix).

        "Reset MQD" has the meaning given such term in Section 5.11(e).

        "Reset Notice" has the meaning given such term in Section 5.11(b).

        "Retained Converted Subordinated Unit" has the meaning given such term in Section 5.5(c)(ii).

        "Second Liquidation Target Amount" has the meaning given such term in Section 6.1(c)(i)(E).

        "Second Target Distribution" means $[            ] per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on                        , 2012, it means the product of $ [            ] multiplied by a fraction of which the numerator is equal to the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

        "Securities Act" means the Securities Act of 1933, as amended, supplemented or restated from time to time, and any successor to such statute.

        "Selling Holder" means a Holder who is selling Registrable Securities pursuant to the procedures in Section 7.12.

        "Share of Additional Book Basis Derivative Items" means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders' Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner's Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

        "Special Approval" means approval by a majority of the members of the Conflicts Committee acting in good faith.

        "Subordinated Unit" means a Limited Partner Interest having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term "Subordinated Unit" does not include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

        "Subordination Period" means the period commencing on the Closing Date and ending on the first to occur of the following dates:

        (a)   the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending                        , 2015 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units, Subordinated Units and General Partner Units and any other

A-17

---

Table of Contents

Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case in respect of such periods and (B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and General Partner Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such periods on a Fully Diluted Weighted Average Basis, and (ii) there are no Cumulative Common Unit Arrearages.

        (b)   the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending                                    , 2013 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case with respect to the four-Quarter period immediately preceding such date equaled or exceeded 150% of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, in each case in respect of such period, and (B) the Adjusted Operating Surplus for the four-Quarter period immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and General Partner Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such period on a Fully Diluted Weighted Average Basis, plus the corresponding Incentive Distributions and (ii) there are no Cumulative Common Unit Arrearages.

        (c)   the date on which the General Partner is removed in a manner described in Section 11.4.

        "Subsidiary" means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

        "Surviving Business Entity" has the meaning given such term in Section 14.2(b).

        "Target Distributions" means, collectively, the First Target Distribution, Second Target Distribution and Third Target Distribution.

        "Third Target Distribution" means $[            ] per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on                        , 2012, it means the product of $ [            ] multiplied by a fraction of which the numerator is equal to the number of days in such

A-18

---

Table of Contents

period and of which the denominator is 92), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

        "Trading Day" means a day on which the principal National Securities Exchange on which the referenced Partnership Interests of any class are listed or admitted for trading is open for the transaction of business or, if such Partnership Interests are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City are not legally required to be closed.

        "Transaction Documents" has the meaning given such term in Section 7.1(b).

        "transfer" has the meaning given such term in Section 4.4(a).

        "Transfer Agent" means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the General Partner to act as registrar and transfer agent for any class of Partnership Interests in accordance with the Exchange Act and the rules of the National Securities Exchange on which such Partnership Interests are listed (if any); provided that, if no such Person is appointed as registrar and transfer agent for any class of Partnership Interests, the General Partner shall act as registrar and transfer agent for such class of Partnership Interests.

        "Treasury Regulation" means the United States Treasury regulations promulgated under the Code.

        "Underwritten Offering" means (a) an offering pursuant to a Registration Statement in which Partnership Interests are sold to an underwriter on a firm commitment basis for reoffering to the public (other than the Initial Public Offering), (b) an offering of Partnership Interests pursuant to a Registration Statement that is a "bought deal" with one or more investment banks, and (c) an "at-the-market" offering pursuant to a Registration Statement in which Partnership Interests are sold to the public through one or more investment banks or managers on a best efforts basis.

        "Unit" means a Partnership Interest that is designated by the General Partner as a "Unit" and shall include Common Units and Subordinated Units but shall not include (i) General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

        "Unit Majority" means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class, and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units.

        "Unitholders" means the Record Holders of Units.

        "Unpaid MQD" has the meaning given such term in Section 6.1(c)(i)(B).

        "Unrealized Gain" attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

        "Unrealized Loss" attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

        "Unrecovered Initial Unit Price" means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an

A-19

---

Table of Contents

Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

        "Unrestricted Person" means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an "Unrestricted Person" for purposes of this Agreement from time to time.

        "U.S. GAAP" means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

        "Withdrawal Opinion of Counsel" has the meaning given such term in Section 11.1(b).

        "Working Capital Borrowings" means borrowings incurred pursuant to a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to the Partners; provided that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months from the date of such borrowings other than from additional Working Capital Borrowings.

        Section 1.2    Construction.     Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms "include," "includes," "including" or words of like import shall be deemed to be followed by the words "without limitation"; and (d) the terms "hereof," "herein" or "hereunder" refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement. The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. To the fullest extent permitted by law, any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in good faith shall, in each case, be conclusive and binding on all Partners, each other Person or Group who acquires an interest in a Partnership Interest and all other Persons for all purposes.

ARTICLE II.
ORGANIZATION

        Section 2.1    Formation.     The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Summit Midstream Partners, LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties, liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

        Section 2.2    Name.     The name of the Partnership shall be "Summit Midstream Partners, LP". Subject to applicable law, the Partnership's business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words "Limited Partnership," "L.P.," "Ltd." or similar words or letters shall be included in the Partnership's name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

A-20

---

Table of Contents

        Section 2.3    Registered Office; Registered Agent; Principal Office; Other Offices.     Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at The Corporation Trust Center, 1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 2100 McKinney Avenue, Suite 1250, Dallas, Texas 75201, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 2100 McKinney Avenue, Suite 1250, Dallas, Texas 75201, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

        Section 2.4    Purpose and Business.     The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve the conduct by the Partnership of any business and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity and the General Partner in determining whether to propose or approve the conduct by the Partnership of any business shall be permitted to do so in its sole and absolute discretion.

        Section 2.5    Powers.     The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

        Section 2.6    Term.     The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

        Section 2.7    Title to Partnership Assets.     Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees of the General Partner or its Affiliates, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees of the General Partner or its Affiliates shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the

A-21

---

Table of Contents

General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership or one or more of the Partnership's designated Affiliates as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to any successor General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III.
RIGHTS OF LIMITED PARTNERS

        Section 3.1    Limitation of Liability.     The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

        Section 3.2    Management of Business.     No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership's business, transact any business in the Partnership's name or have the power to sign documents for or otherwise bind the Partnership. No action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall be deemed to be participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) nor shall any such action affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

        Section 3.3    Rights of Limited Partners.     

        (a)   Each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner's interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner's own expense:

          (i)  to obtain from the General Partner either (A) the Partnership's most recent filings with the Commission on Form 10-K and any subsequent filings on Form 10-Q and 8-K or (B) if the Partnership is no longer subject to the reporting requirements of the Exchange Act, the information specified in, and meeting the requirements of, Rule 144A(d)(4) under the Securities Act (provided that the foregoing materials shall be deemed to be available to a Limited Partner in satisfaction of the requirements of this Section 3.3(a)(i) if posted on or accessible through the Partnership's or the Commission's website);

         (ii)  to obtain a current list of the name and last known business, residence or mailing address of each Partner; and

        (iii)  to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto.

        (b)   To the fullest extent permitted by law, the rights to information granted to the Limited Partners pursuant to Section 3.3(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners and each other Person or Group who acquires an interest in the Partnership hereby agrees to the fullest extent permitted by law that they do not have any rights as Partners or interest holders to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.3(a).

A-22

---

Table of Contents

        (c)   The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.3).

        (d)   Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Partners, each other Person or Group who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person or Group.

ARTICLE IV.
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP
INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

        Section 4.1    Certificates.     Record Holders of Partnership Interests and, where appropriate, Derivative Partnership Interests, shall be recorded in the Partnership Register and ownership of such interests shall be evidenced by a physical certificate or book entry notation in the Partnership Register. Notwithstanding anything to the contrary in this Agreement, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by physical certificates. Certificates, if any, shall be executed on behalf of the Partnership by the Chief Executive Officer, President, Chief Financial Officer or any Senior Vice President or Vice President and the Secretary, any Assistant Secretary, or other authorized officer of the General Partner, and shall bear the legend set forth in Section 4.8(e). The signatures of such officers upon a certificate may, to the extent permitted by law, be facsimiles. In case any officer who has signed or whose signature has been placed upon such certificate shall have ceased to be such officer before such certificate is issued, it may be issued by the Partnership with the same effect as if he were such officer at the date of its issuance. If a Transfer Agent has been appointed for a class of Partnership Interests, no Certificate for such class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that, if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(b) and Section 6.7(c), if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7, the Record Holders of such Subordinated Units (a) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing the Common Units into which such Record Holder's Subordinated Units converted, or (b) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing the Common Units into which such Record Holders' Subordinated Units converted. With respect to any Partnership Interests that are represented by physical certificates, the General Partner may determine that such Partnership Interests will no longer be represented by physical certificates and may, upon written notice to the holders of such Partnership Interests and subject to applicable law, take whatever actions it deems necessary or appropriate to cause such Partnership Interests to be registered in book entry or global form and may cause such physical certificates to be cancelled or deemed cancelled.

A-23

---

Table of Contents

        Section 4.2    Mutilated, Destroyed, Lost or Stolen Certificates.     

        (a)   If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

        (b)   The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued, if the Record Holder of the Certificate:

          (i)  makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

         (ii)  requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

        (iii)  if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

        (iv)  satisfies any other reasonable requirements imposed by the General Partner or the Transfer Agent.

        If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, to the fullest extent permitted by law, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

        (c)   As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

        Section 4.3    Record Holders.     The names and addresses of Unitholders as they appear in the Partnership Register, as applicable, shall be the official list of Record Holders of the Partnership Interests for all purposes. The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person or Group, regardless of whether the Partnership or the General Partner shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person or Group in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Person on the other, such representative Person shall be the Limited Partner with respect to such Partnership Interest upon becoming the Record Holder in accordance with Section 10.1(b) and have the rights and obligations of a Partner hereunder as, and to the extent, provided herein, including Section 10.1(c).

A-24

---

Table of Contents

        Section 4.4    Transfer Generally.     

        (a)   The term "transfer," when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns all or any part of its General Partner Interest (represented by General Partner Units) to another Person and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest assigns all or any part of such Limited Partner Interest to another Person who is or becomes a Limited Partner as a result thereof, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

        (b)   No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void, and the Partnership shall have no obligation to effect any such transfer or purported transfer.

        (c)   Nothing contained in this Agreement shall be construed to prevent or limit a disposition by any stockholder, member, partner or other owner of the General Partner or any Limited Partner of any or all of such Person's shares of stock, membership interests, partnership interests or other ownership interests in the General Partner or such Limited Partner and the term "transfer" shall not include any such disposition.

        Section 4.5    Registration and Transfer of Limited Partner Interests.     

        (a)   The General Partner shall maintain, or cause to be maintained, by the Transfer Agent in whole or in part, the Partnership Register on behalf of the Partnership.

        (b)   The General Partner shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until endorsed Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of this Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder's instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered. Upon the proper surrender of a Certificate, such transfer shall be recorded in the Partnership Register.

        (c)   Upon the receipt of proper transfer instructions from the Record Holder of uncertificated Partnership Interests, such transfer shall be recorded in the Partnership Register.

        (d)   Except as provided in Section 4.9, by acceptance of any Limited Partner Interests pursuant to a transfer in accordance with this Article IV, each transferee of a Limited Partner Interest (including any nominee, or agent or representative acquiring such Limited Partner Interests for the account of another Person or Group) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the Partnership Register and such Person becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) makes the consents, acknowledgements and waivers

A-25

---

Table of Contents

contained in this Agreement, all with or without execution of this Agreement by such Person and (v) shall be deemed to certify that the transferee is not an Ineligible Holder. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

        (e)   Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

        (f)    The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

        Section 4.6    Transfer of the General Partner's General Partner Interest.     

        (a)   Subject to Section 4.6(c) below, prior to                        , 2022 the General Partner shall not transfer all or any part of its General Partner Interest (represented by General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

        (b)   Subject to Section 4.6(c) below, on or after                    , 2022 the General Partner may transfer all or any part of its General Partner Interest without the approval of any Person.

        (c)   Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest owned by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

        Section 4.7    Transfer of Incentive Distribution Rights.     The General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without the approval of any Person.

        Section 4.8    Restrictions on Transfers.     

        (a)   Except as provided in Section 4.8(d), notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer,

A-26

---

Table of Contents

(ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed). The Partnership may issue stop transfer instructions to any Transfer Agent in order to implement any restriction on transfer contemplated by this Agreement.

        (b)   The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to (i) avoid a significant risk of the Partnership's becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes (to the extent not already so treated or taxed) or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

        (c)   The transfer of a Subordinated Unit or a Common Unit issued upon conversion of a Subordinated Unit shall be subject to the restrictions imposed by Section 6.7(b) and Section 6.7(c).

        (d)   Except for Section 4.9, nothing in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

        (e)   Each certificate or book entry evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

        THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF SUMMIT MIDSTREAM PARTNERS, LP THAT THIS SECURITY MAY NOT BE TRANSFERRED IF SUCH TRANSFER (AS DEFINED IN THE PARTNERSHIP AGREEMENT) WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF SUMMIT MIDSTREAM PARTNERS, LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE SUMMIT MIDSTREAM PARTNERS, LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). THE GENERAL PARTNER OF SUMMIT MIDSTREAM PARTNERS, LP MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF SUMMIT MIDSTREAM PARTNERS, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THIS SECURITY MAY BE SUBJECT TO ADDITIONAL RESTRICTIONS ON ITS TRANSFER PROVIDED IN THE PARTNERSHIP AGREEMENT. COPIES OF SUCH AGREEMENT MAY BE OBTAINED AT NO COST BY WRITTEN REQUEST MADE BY THE HOLDER OF RECORD OF THIS SECURITY TO THE SECRETARY OF THE GENERAL PARTNER AT THE PRINCIPAL EXECUTIVE OFFICES OF THE PARTNERSHIP. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

A-27

---

Table of Contents

        Section 4.9    Eligibility Certificates; Ineligible Holders.     

        (a)   The General Partner may upon demand or on a regular basis require Limited Partners, and transferees of Limited Partner Interests in connection with a transfer, to execute an Eligibility Certificate or provide other information as is necessary for the General Partner to determine if any such Limited Partners or transferees are Ineligible Holders.

        (b)   If any Limited Partner (or its beneficial owners) fails to furnish to the General Partner within 30 days of its request an Eligibility Certificate and other information related thereto, or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner or a transferee of a Limited Partner is an Ineligible Holder, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10 or the General Partner may refuse to effect the transfer of the Limited Partner Interests to such transferee. In addition, the General Partner shall be substituted for any Limited Partner that is an Ineligible Holder as the Limited Partner in respect of the Ineligible Holder's Limited Partner Interests.

        (c)   The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Limited Partners (including the General Partner and its Affiliates) in respect of Limited Partner Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

        (d)   Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder's share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of its Limited Partner Interest (representing the right to receive its share of such distribution in kind).

        (e)   At any time after an Ineligible Holder can and does certify that it no longer is an Ineligible Holder, it may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Ineligible Holder not redeemed pursuant to Section 4.10, such Ineligible Holder upon approval of the General Partner, shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Limited Partner in respect of such Limited Partner Interests.

        (f)    If at any time a transferee of a Limited Partner Interest fails to furnish an Eligibility Certificate or any other information requested by the General Partner pursuant to Section 4.9 within 30 days of such request, or if upon receipt of such Eligibility Certificate or other information the General Partner determines, with the advice of counsel, that such transferee is an Ineligible Holder, the Partnership may, unless the transferee establishes to the satisfaction of the General Partner that such transferee is not an Ineligible Holder, prohibit and void the transfer, including by placing a stop order with the Transfer Agent.

        Section 4.10    Redemption of Partnership Interests of Ineligible Holders.     

        (a)   If at any time a Limited Partner fails to furnish an Eligibility Certificate or any other information requested within the period of time specified in Section 4.9, or if upon receipt of such Eligibility Certificate or other information the General Partner determines, with the advice of counsel, that a Limited Partner is an Ineligible Holder, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is not an Ineligible Holder or has transferred his Limited Partner Interests to a Person who is not an Ineligible Holder and

A-28

---

Table of Contents

who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

          (i)  The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at such Limited Partner's last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which such Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

         (ii)  The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

        (iii)  The Limited Partner or such Limited Partner's duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Limited Partner or Transferee at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

        (iv)  After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

        (b)   The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee, agent or representative of a Person determined to be an Ineligible Holder.

        (c)   Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement and the transferor provides notice of such transfer to the General Partner. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that such transferee is not an Ineligible Holder. If the transferee fails to make such certification within 30 days after the request and, in any event, before the redemption date, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V.
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

        Section 5.1    Organizational Contributions.     In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $20.00, for a 2% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $980.00 for a 98% Limited Partner Interest in the

A-29

---

Table of Contents

Partnership and has been admitted as a Limited Partner of the Partnership. [As of the Closing Date, the interests of the Organizational Limited Partner shall be partially redeemed as provided in the Contribution Agreement and the Organizational Limited Partner shall continue as a Limited Partner of the Partnership and the initial Capital Contributions of the Organizational Limited Partner shall be refunded, and all interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, respectively.] The Organizational Limited Partner hereby continues as a limited partner of the Partnership with respect to the portion of its interest that is not partially redeemed.

        Section 5.2    Contributions by the General Partner and its Affiliates.     

        (a)   On the Closing Date and pursuant to the Contribution Agreement, the General Partner contributed to the Partnership, as a Capital Contribution, a [            ]% interest in the Operating Company, in exchange for (i) [            ] General Partner Units representing a continuation of its 2% General Partner Interest, subject to all of the rights, privileges and duties of the General Partner under this Agreement and (ii) the Incentive Distribution Rights. On the Closing Date and pursuant to the Contribution Agreement, Summit Midstream Partners, LLC contributed to the Partnership, as a Capital Contribution, a [            ]% limited liability company member interest in the Operating Company, in exchange for (i) [            ]Common Units, (ii)  [            ] Subordinated Units, (iii) a right to receive $[            ] million in part as a reimbursement for certain capital expenditures incurred with respect to the assets of the Operating Company pursuant to Treasury Regulation Section 1.707-4(d), and (iv) the Partnership's assumption of the remaining balance of loans used to acquire certain assets owned by the Operating Company.

        (b)   Upon the issuance of any additional Limited Partner Interests by the Partnership (other than (i) the Common Units issued in the Initial Public Offering, (ii) the Common Units, Subordinated Units and Incentive Distribution Rights issued pursuant to Section 5.3(a), (iii) any Common Units issued pursuant to Section 5.11 and (iv) any Common Units issued upon the conversion of any Partnership Interests), the General Partner may, in order to maintain the Percentage Interest with respect to its General Partner Interest, make additional Capital Contributions in an amount equal to the product obtained by multiplying (A) the quotient determined by dividing (x) the Percentage Interest with respect to the General Partner Interests immediately prior to the issuance of such additional Limited Partner Interests by the Partnership by (y) 100% less the Percentage Interest with respect to the General Partner Interest immediately prior to the issuance of such additional Limited Partner Interests by the Partnership times (B) the gross amount contributed to the Partnership by the Limited Partners (before deduction of underwriters' discounts and commissions) in exchange for such additional Limited Partner Interests. Any capital Contribution pursuant to this Section 5.2(b) shall be evidenced by the issuance to the General Partner of a proportionate number of additional General Partner Units.

        Section 5.3    Contributions by Limited Partners unaffiliated with the General Partner.     

        (a)   On the Closing Date and pursuant to the IPO Underwriting Agreement, each IPO Underwriter contributed cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each IPO Underwriter, all as set forth in the IPO Underwriting Agreement.

        (b)   Upon the exercise, if any, of the Over-Allotment Option, each IPO Underwriter shall contribute cash to the Partnership on the Option Closing Date in exchange for the issuance by the Partnership of Common Units to each IPO Underwriter, all as set forth in the IPO Underwriting Agreement. Upon receipt by the Partnership of the Capital Contributions from the Underwriters as provided in this Section 5.3(b), the Partnership shall use such cash to redeem from the Organizational Limited Partner that number of Common Units held by the Organizational Limited Partner, equal to the number of Common Units issued to the Underwriters as provided in this Section 5.3(b).

A-30

---

Table of Contents

        (c)   No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units and Subordinated Units issued to Summit Midstream Partners, LLC, pursuant to subparagraph (a) of Section 5.2, (ii) the Common Units issued to the IPO Underwriters as described in subparagraphs (a) and (b) of this Section 5.3 and (iii) the Incentive Distribution Rights issued to the General Partner.

        (d)   No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

        Section 5.4    Interest and Withdrawal.     No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

        Section 5.5    Capital Accounts.     

        (a)   The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee, agent or representative in any case in which such nominee, agent or representative has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). The initial Capital Account balance attributable to the General Partner Units issued to the General Partner pursuant to Section 5.2(a) shall equal the Net Agreed Value of the Capital Contribution specified in Section 5.2(a), which shall be deemed to equal the product of the number of General Partner Units issued to the General Partner pursuant to Section 5.2(a) and the Initial Unit Price for each Common Unit (and the initial Capital Account balance attributable to each General Partner Unit shall equal the Initial Unit Price for each Common Unit). The initial Capital Account balance attributable to the Common Units and Subordinated Units issued to Summit Midstream Partners, LLC pursuant to Section 5.2(a) shall equal the respective Net Agreed Value of the Capital Contributions specified in Section 5.2(a), which shall be deemed to equal the product of the number of Common Units and Subordinated Units issued to Summit Midstream Partners, LLC pursuant to Section 5.2(a) and the Initial Unit Price for each such Common Unit and Subordinated Unit (and the initial Capital Account balance attributable to each such Common Unit and Subordinated Unit shall equal its Initial Unit Price). The initial Capital Account balance attributable to the Common Units issued to the IPO Underwriters pursuant to Section 5.3(a) shall equal the product of the number of Common Units so issued to the IPO Underwriters and the Initial Unit Price for each Common Unit (and the initial Capital Account balance attributable to each such Common Unit shall equal its Initial Unit Price). The initial Capital Account attributable to the Incentive Distribution Rights shall be zero. Thereafter, the Capital Account shall in respect of each such Partnership Interest be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

A-31

---

Table of Contents

        (b)   For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners' Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

          (i)  Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership or disregarded entity for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership or disregarded entity for federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

         (ii)  All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

        (iii)  Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

        (iv)  Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership's Carrying Value with respect to such property as of such date.

         (v)  An item of income of the Partnership that is described in Section 705(a)(1)(B) of the Code (with respect to items of income that are exempt from tax) shall be treated as an item of income for the purpose of this Section 5.5(b), and an item of expense of the Partnership that is described in Section 705(a)(2)(B) of the Code (with respect to expenditures that are not deductible and not chargeable to capital accounts), shall be treated as an item of deduction for the purpose of this Section 5.5(b).

        (vi)  In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

       (vii)  The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for

A-32

---

Table of Contents

purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

        (c)   (i) The transferee of a Partnership Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

         (ii)  Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any converted Subordinated Units ("Retained Converted Subordinated Units") or Subordinated Units. Following any such allocation, the transferor's Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee's Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

        (d)   (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services, or the conversion of the General Partner's Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of each Partner and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated; provided, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may determine that it is appropriate to first determine an aggregate value for the Partnership, derived from the current trading price of the Common Units, and taking fully into account the fair market value of the Partnership Interests of all Partners at such time, and then allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate).

         (ii)  In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted

A-33

---

Table of Contents

upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated among the Partners, at such time, pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

        Section 5.6    Issuances of Additional Partnership Interests.     

        (a)   The Partnership may issue additional Partnership Interests (other than General Partner Interests not issued pursuant to Section 5.2(b)) and Derivative Partnership Interests for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

        (b)   Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest; (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by Certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

        (c)   The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Partnership Interests pursuant to this Section 5.6, (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) the issuance of Common Units pursuant to Section 5.11, (iv) reflecting admission of such additional Limited Partners in the Partnership Register as the Record Holders of such Limited Partner Interests and (v) all additional issuances of Partnership Interests and Derivative Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or Derivative Partnership Interests or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

        (d)   No fractional Units shall be issued by the Partnership.

A-34

---

Table of Contents

        Section 5.7    Conversion of Subordinated Units.     

        (a)   All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the expiration of the Subordination Period.

        (b)   A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7.

        Section 5.8    Limited Preemptive Right.     Except as provided in this Section 5.8 and in Section 5.2 and Section 5.11 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests.

        Section 5.9    Splits and Combinations.     

        (a)   Subject to Section 5.9(e), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.

        (b)   Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice (or such shorter periods as required by applicable law). The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

        (c)   If a Pro Rata distribution of Partnership Interests, or a subdivision or combination of Partnership Interests, is made as contemplated in this Section 5.9, the number of General Partner Units constituting the Percentage Interest of the General Partner (as determined immediately prior to the Record Date for such distribution, subdivision or combination) shall be appropriately adjusted as of the date of payment of such distribution, or the effective date of such subdivision or combination, to maintain such Percentage Interest of the General Partner.

        (d)   Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of Partnership Interests represented by Certificates, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

A-35

---

Table of Contents

        (e)   The Partnership shall not issue fractional Units or fractional General Partner Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units and General Partner Units but for the provisions of Section 5.6(d) and this Section 5.9(e), each fractional Unit and General Partner Unit shall be rounded to the nearest whole Unit or General Partner Unit (with fractional Units or General Partner Unit equal to or greater than a 0.5 Unit or General Partner Unit being rounded to the next higher Unit or General Partner Unit).

        Section 5.10    Fully Paid and Non-Assessable Nature of Limited Partner Interests.     All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Sections 17-303, 17-607 or 17-804 of the Delaware Act.

        Section 5.11    Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.     

        (a)   Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, at any time when there are no Subordinated Units Outstanding and the Partnership has made a distribution pursuant to Section 6.4(b)(v) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the "IDR Reset Election") to cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Common Units (the "IDR Reset Common Units") derived by dividing (i) the average amount of the aggregate cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b)) in respect of the Incentive Distribution Rights by (ii) the average amount of the aggregate cash distributions made by the Partnership in respect of each Common Unit for the two full Quarters immediately preceding the giving of the Reset Notice (the number of Common Units determined by such quotient is referred to herein as the "Aggregate Quantity of IDR Reset Common Units"). If at the time of any IDR Reset Election the General Partner and its Affiliates are not the holders of a majority in interest of the Incentive Distribution Rights, then the IDR Reset Election shall be subject to the prior written concurrence of the General Partner that the conditions described in the immediately preceding sentence have been satisfied. Upon the issuance of such IDR Reset Common Units, the Partnership will issue to the General Partner that number of additional General Partner Units equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner immediately prior to such issuance by (B) a percentage equal to 100% less such Percentage Interest by (y) the number of such IDR Reset Common Units, and the General Partner shall not be obligated to make any additional Capital Contribution to the Partnership in exchange for such issuance. The making of the IDR Reset Election in the manner specified in this Section 5.11 shall cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive IDR Reset Common Units and the General Partner will become entitled to receive General Partner Units on the basis specified above, without any further approval required by the General Partner or the Unitholders other than as set forth in this Section 5.11(a), at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

        (b)   To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the "Reset Notice") to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset

A-36

---

Table of Contents

Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership's determination of the Aggregate Quantity of IDR Reset Common Units that each holder of Incentive Distribution Rights will be entitled to receive.

        (c)   The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units and the General Partner will be entitled to receive the related additional General Partner Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of IDR Reset Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such IDR Reset Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

        (d)   If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the IDR Reset Common Units to be issued pursuant to this Section 5.11 on or before the 30th calendar day following the Partnership's receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Interests having such terms as the General Partner may approve, with the approval of the Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership's receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion of such Partnership Interests into Common Units within not more than 12 months following the Partnership's receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

        (e)   The Minimum Quarterly Distribution and the Target Distributions, shall be adjusted at the time of the issuance of IDR Reset Common Units or other Partnership Interests pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership's receipt of the Reset Notice (the "Reset MQD"), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, (iii) the Second Target Distribution shall be reset to equal 125% of the Reset MQD and (iv) the Third Target Distribution shall be reset to equal 150% of the Reset MQD.

        (f)    Upon the issuance of IDR Reset Common Units pursuant to Section 5.11(a), the Capital Account maintained with respect to the Incentive Distribution Rights will (i) first, be allocated to IDR Reset Common Units in an amount equal to the product of (A) the Aggregate Quantity of IDR Reset Common Units and (B) the Per Unit Capital Amount for an Initial Common Unit, and (ii) second, as to any remaining balance in such Capital Account, will be retained by the holder of the Incentive Distribution Rights. If there is not sufficient capital associated with the Incentive Distribution Rights to allocate the full Per Unit Capital Amount for an Initial Common Unit to the IDR Reset Common Units in accordance with clause (i) of this Section 5.11(f), the IDR Reset Common Units shall be subject to Sections 6.1(d)(x)(B) and (C).

ARTICLE VI.
ALLOCATIONS AND DISTRIBUTIONS

        Section 6.1    Allocations for Capital Account Purposes.     For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership's items of

A-37

---

Table of Contents

income, gain, loss and deduction (computed in accordance with Section 5.5(b)) for each taxable period shall be allocated among the Partners as provided herein below.

        (a)    Net Income.     After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable period shall be allocated as follows:

          (i)  First, to the General Partner until the aggregate of the Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) and the Net Termination Gain allocated to the General Partner pursuant to Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(D) or Section 6.1(c)(iii)(B) for the current and all previous taxable periods; and

         (ii)  The balance, if any, (x) to the General Partner in accordance with its Percentage Interest, and (y) to all Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x).

        (b)    Net Loss.     After giving effect to the special allocations set forth in Section 6.1(d), Net Loss for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Loss for such taxable period shall be allocated as follows:

          (i)  First, to the General Partner and the Unitholders, Pro Rata; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and

         (ii)  The balance, if any, 100% to the General Partner.

        (c)    Net Termination Gains and Losses.     After giving effect to the special allocations set forth in Section 6.1(d), Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

          (i)  Except as provided in Section 6.1(c)(iv), Net Termination Gain (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Gain) shall be allocated:

        (A)  First, to the General Partner until the aggregate of the Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) and the Net Income allocated to the General Partner pursuant to Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(D) or Section 6.1(c)(iii)(B) for all previous taxable periods;

        (B)  Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the

A-38

---

Table of Contents

Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter referred to as the "Unpaid MQD") and (3) any then existing Cumulative Common Unit Arrearage;

        (C)  Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit into a Common Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable period (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

        (D)  Fourth, 100% to the General Partner and all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership's existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of subclauses (1), (2), (3) and (4) is hereinafter referred to as the "First Liquidation Target Amount");

        (E)  Fifth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (E), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership's existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of subclauses (1) and (2) is hereinafter referred to as the "Second Liquidation Target Amount");

        (F)  Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter of the Partnership's existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv); and

        (G)  Finally, (x) to the General Partner in accordance with its Percentage Interest, (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (G).

A-39

---

Table of Contents

         (ii)  Except as otherwise provided by Section 6.1(c)(iii), Net Termination Loss (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Loss) shall be allocated:

        (A)  First, if Subordinated Units remain Outstanding, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

        (B)  Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero;

        (C)  Third, to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(ii)(C) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account (or increase any existing deficit in its Adjusted Capital Account); and

        (D)  Fourth, the balance, if any, 100% to the General Partner.

        (iii)  Any Net Termination Loss deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:

        (A)  First, to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(A) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and

        (B)  The balance, if any, to the General Partner.

        (iv)  If a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii), subsequent Net Termination Gain deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:

        (A)  First, to the General Partner until the aggregate Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(iv)(A) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(B);

        (B)  Second, to the General Partner and the Unitholders, Pro Rata, until the aggregate Net Termination Gain allocated pursuant to this Section 6.1(c)(iv)(B) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(A); and

        (C)  The balance, if any, pursuant to the provisions of Section 6.1(c)(i).

        (d)    Special Allocations.     Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

        (i)    Partnership Minimum Gain Chargeback.    Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner's Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of

A-40

---

Table of Contents

any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

        (ii)    Chargeback of Partner Nonrecourse Debt Minimum Gain.    Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner's Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) and other than an allocation pursuant to Section 6.1(d)(i), Section 6.1(d)(vi) and Section 6.1(d)(vii) with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

        (iii)    Priority Allocations.    

        (A)  If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit (the amount of the excess, an "Excess Distribution" and the Unit with respect to which the greater distribution is paid, an "Excess Distribution Unit"), then (1) there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(d)(iii)(A) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution; and (2) the General Partner shall be allocated gross income and gain with respect to each such Excess Distribution in an amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner's Percentage Interest at the time when the Excess Distribution occurs by (y) a percentage equal to 100% less the General Partner's Percentage Interest at the time when the Excess Distribution occurs, times (bb) the total amount allocated in clause (1) above with respect to such Excess Distribution.

        (B)  After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable period; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner's Percentage Interest by (y) the sum of 100 less the General Partner's Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

        (iv)    Qualified Income Offset.    In the event any Partner unexpectedly receives any adjustment, allocation or distribution described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall

A-41

---

Table of Contents

be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.

        (v)    Gross Income Allocation.    In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(d)(iv) and this Section 6.1(d)(v) were not in this Agreement.

        (vi)    Nonrecourse Deductions.    Nonrecourse Deductions for any taxable period shall be allocated to the Partners Pro Rata. If the General Partner determines that the Partnership's Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

        (vii)    Partner Nonrecourse Deductions.    Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, the Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

        (viii)    Nonrecourse Liabilities.    For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners Pro Rata.

        (ix)    Code Section 754 Adjustments.    To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

        (x)    Economic Uniformity; Changes in Law.    

        (A)  At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding

A-42

---

Table of Contents

Subordinated Units that are Outstanding as of the termination of the Subordination Period ("Final Subordinated Units") in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (1) the number of Final Subordinated Units held by such Partner and (2) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

        (B)  With respect to an event triggering an adjustment to the Carrying Value of Partnership property pursuant to Section 5.5(d) during any taxable period of the Partnership ending upon, or after, the issuance of IDR Reset Common Units pursuant to Section 5.11, after the application of Section 6.1(d)(x)(A), any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to such IDR Reset Common Units issued pursuant to Section 5.11 equaling the product of (1) the Aggregate Quantity of IDR Reset Common Units and (2) the Per Unit Capital Amount for an Initial Common Unit.

        (C)  With respect to any taxable period during which an IDR Reset Common Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred IDR Reset Common Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred IDR Reset Common Unit to an amount equal to the Per Unit Capital Amount for an Initial Common Unit.

        (D)  For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (1) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (2) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (3) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x)(D) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

        (xi)    Curative Allocation.    

        (A)  Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed

A-43

---

Table of Contents

Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. In exercising its discretion under this Section 6.1(d)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

        (B)  The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

        (xii)    Corrective and Other Allocations.    In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

        (A)  Except as provided in Section 6.1(d)(xii)(B), in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof), the General Partner shall allocate such Additional Book Basis Derivative Items to (1) the holders of Incentive Distribution Rights and the General Partner to the same extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to them pursuant to Section 5.5(d) and (2) all Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to any Unitholders pursuant to Section 5.5(d).

        (B)  In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof or an allocation of Net Termination Gain or Net Termination Loss pursuant to Section 6.1(c) hereof) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property ("Disposed of Adjusted Property"), the General Partner shall allocate (1) additional items of gross income and gain (aa) away from the holders of Incentive Distribution Rights and (bb) to the Unitholders, or (2) additional items of deduction and loss (aa) away from the Unitholders and (bb) to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

A-44

---

Table of Contents

        (C)  In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balances of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

        (D)  For purposes of this Section 6.1(d)(xii), the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement. In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the "lower tier partnership"), the General Partner may make allocations similar to those described in Sections 6.1(d)(xii)(A) through (C) to the extent the General Partner determines such allocations are necessary to account for the Partnership's allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii).

        (xiii)    Special Curative Allocation in Event of Liquidation Prior to End of Subordination Period.     Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit, then items of income, gain, loss and deduction for the taxable period that includes the Liquidation Date (and, if necessary, items arising in previous taxable periods to the extent the General Partner determines such items may be so allocated), shall be specially allocated among the Partners in the manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.

        Section 6.2    Allocations for Tax Purposes.     

        (a)   Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of "book" income, gain, loss or deduction is allocated pursuant to Section 6.1.

        (b)   In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined to be appropriate by the General Partner (taking into account the General Partner's discretion under Section 6.1(d)(x)(D)); provided, that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.

        (c)   The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot

A-45

---

Table of Contents

reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership's property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

        (d)   In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

        (e)   All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

        (f)    Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, that such items for the period beginning on the Closing Date and ending on the last day of the month in which the last Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

        (g)   Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee, agent or representative in any case in which such nominee, agent or representative has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

        Section 6.3    Requirement and Characterization of Distributions; Distributions to Record Holders.     

        (a)   Within 45 days following the end of each Quarter commencing with the Quarter ending on                        , 2012, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. The Record Date for the first distribution of Available Cash shall not be prior to the final closing of the Over-Allotment Option. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum

A-46

---

Table of Contents

of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be "Capital Surplus." All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act and other applicable law, notwithstanding any other provision of this Agreement.

        (b)   Notwithstanding Section 6.3(a) (but subject to the last sentence of Section 6.3(a)), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

        (c)   The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners, as determined appropriate under the circumstances by the General Partner.

        (d)   Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership's liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

        Section 6.4    Distributions of Available Cash from Operating Surplus.     

        (a)   During the Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5 shall be distributed as follows, except as otherwise required in respect of additional Partnership Interests issued pursuant to Section 5.6(b):

          (i)  First, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

         (ii)  Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

        (iii)  Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

        (iv)  Fourth, to the General Partner and all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

         (v)  Fifth, (A) to the General Partner in accordance with its Percentage Interest, (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v), until there has been distributed in respect of each Unit then Outstanding an

A-47

---

Table of Contents

amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

        (vi)  Sixth, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

       (vii)  Thereafter, (A) to the General Partner in accordance with its Percentage Interest, (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vii);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vii).

        (b)   After the Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall be distributed as follows, except as otherwise required in respect of additional Partnership Interests issued pursuant to Section 5.6(b):

          (i)  First, to the General Partner and all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

         (ii)  Second, to the General Partner and all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

        (iii)  Third, (A) to the General Partner in accordance with its Percentage Interest, (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

        (iv)  Fourth, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

         (v)  Thereafter, (A) to the General Partner in accordance with its Percentage Interest, (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);

provided, however, that if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(v).

A-48

---

Table of Contents

        Section 6.5    Distributions of Available Cash from Capital Surplus.     Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall be distributed, unless the provisions of Section 6.3 require otherwise, to the General Partner and the Unitholders, Pro Rata, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price. Available Cash that is deemed to be Capital Surplus shall then be distributed (A) to the General Partner in accordance with its Percentage Interest and (B) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner's Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

        Section 6.6    Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.     

        (a)   The Minimum Quarterly Distribution, Target Distributions, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution and Target Distributions shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Initial Unit Price of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Initial Unit Price of the Common Units immediately prior to giving effect to such distribution.

        (b)   The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

        Section 6.7    Special Provisions Relating to the Holders of Subordinated Units.     

        (a)   Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder with respect to such converted Subordinated Units, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x)(A), 6.7(b) and 6.7(c).

        (b)   A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder's Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

        (c)   The holder of a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 or Section 11.4 shall not be issued a Common Unit Certificate pursuant to Section 4.1 (if the Common Units are represented by Certificates) and shall not be permitted to

A-49

---

Table of Contents

transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

        Section 6.8    Special Provisions Relating to the Holders of Incentive Distribution Rights.     

        (a)   Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (ii) be entitled to any distributions other than as provided in Sections 6.4(a)(v), (vi) and (vii), Sections 6.4(b)(iii), (iv) and (v), and Section 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI; provided, however, that, for the avoidance of doubt, the foregoing shall not preclude the Partnership from making any other payments or distributions in connection with other actions permitted by this Agreement.

        (b)   A holder of an IDR Reset Common Unit that was issued in connection with an IDR Reset Election pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1 (if the Common Units are evidenced by Certificates) or evidence of the issuance of uncertified Common Units, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of such holder, until such time as the General Partner determines, based on advice of counsel, that each such IDR Reset Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.8(b), the General Partner may take whatever steps are required to provide economic uniformity to such IDR Reset Common Units in preparation for a transfer of such IDR Reset Common Units, including the application of Section 5.5(c)(iii), Section 6.1(d)(x)(B), or Section 6.1(d)(x)(C); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

        Section 6.9    Entity-Level Taxation.     If legislation is enacted or the official interpretation of existing legislation is modified by a governmental authority, which after giving effect to such enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member prior to such enactment or modification (including, for the avoidance of doubt, any increase in the rate of such taxation applicable to the Group Member), then the General Partner may, at its option, reduce the Minimum Quarterly Distribution and the Target Distributions by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the "Incremental Income Taxes"), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General Partner elects to reduce the Minimum Quarterly Distribution and the Target Distributions for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group's aggregate liability (the "Estimated Incremental Quarterly Tax Amount") for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such estimate and the actual liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated

A-50

---

Table of Contents

Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII.
MANAGEMENT AND OPERATION OF BUSINESS

        Section 7.1    Management.     

        (a)   The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

          (i)  the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for Partnership Interests, and the incurring of any other obligations;

         (ii)  the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

        (iii)  the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

        (iv)  the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

         (v)  the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

        (vi)  the distribution of Partnership cash;

A-51

---

Table of Contents

       (vii)  the selection and dismissal of officers, employees, agents, internal and outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

      (viii)  the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

        (ix)  the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

         (x)  the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

        (xi)  the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

       (xii)  the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

      (xiii)  the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of Derivative Partnership Interests;

      (xiv)  the undertaking of any action in connection with the Partnership's participation in the management of any Group Member; and

       (xv)  the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

        (b)   Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Interests or that is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the IPO Underwriting Agreement, the Contribution Agreement and the other agreements described in or filed as exhibits to the IPO Registration Statement that are related to the transactions contemplated by the IPO Registration Statement (collectively, the "Transaction Documents") (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements thereof entered into after the date such Person becomes bound by the provisions of this Agreement); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the IPO Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or are otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any

A-52

---

Table of Contents

duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

        Section 7.2    Certificate of Limited Partnership.     The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.3(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

        Section 7.3    Restrictions on the General Partner's Authority to Sell Assets of the Partnership Group.     Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner's ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

        Section 7.4    Reimbursement of the General Partner.     

        (a)   Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

        (b)   The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner, to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner or its Affiliates in connection with managing and operating the Partnership Group's business and affairs (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7. Any allocation of expenses to the Partnership by Affiliates of the General Partner in a manner consistent with past business practices and, in the case of assets regulated by FERC, then-applicable accounting and allocation methodologies generally permitted by FERC for rate-making purposes (or in the absence of then-applicable methodologies permitted by FERC, consistent with the most-recently applicably methodologies), shall be deemed to have been made in good faith. This provision does not affect the ability of the General Partner and its Affiliates to enter into an agreement to provide services to any Group Member for a fee or otherwise than for cost.

        (c)   The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans,

A-53

---

Table of Contents

employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Interests or Derivative Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates in each case for the benefit of officers, employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are obligated to provide to any officers, employees, consultants and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner's General Partner Interest pursuant to Section 4.6.

        (d)   The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

        Section 7.5    Outside Activities.     

        (a)   The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the IPO Registration Statement or (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member.

        (b)   Subject to the terms of Section 7.5(c), each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

A-54

---

Table of Contents

        (c)   Subject to the terms of Sections 7.5(a) and (b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement or any duty, otherwise existing at law or in equity, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person bound by this Agreement for breach of any duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided that such Unrestricted Person does not engage in such business or activity using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

        (d)   The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units and/or other Partnership Interests acquired by them. The term "Affiliates" when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

        Section 7.6    Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.     

        (a)   The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm's-length basis (without reference to the lending party's financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term "Group Member" shall include any Affiliate of a Group Member that is controlled by the Group Member.

        (b)   The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

        (c)   No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners existing hereunder, or existing at law, in equity or otherwise by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to

A-55

---

Table of Contents

(i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner's Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

        Section 7.7    Indemnification.     

        (a)   To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity on behalf of or for the benefit of the Partnership; provided, that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in intentional fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee's conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to any Affiliate of the General Partner (other than a Group Member), or to any other Indemnitee, with respect to any such Affiliate's obligations pursuant to the Transaction Documents. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

        (b)   To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

        (c)   The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee's capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the IPO Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

        (d)   The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership's activities or such Person's activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

        (e)   For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its

A-56

---

Table of Contents

duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute "fines" within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

        (f)    In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

        (g)   An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

        (h)   The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

        (i)    No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

        Section 7.8    Liability of Indemnitees.     

        (a)   Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Partnership Interests, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in intentional fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee's conduct was criminal.

        (b)   The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

        (c)   To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership's business or affairs shall not be liable to the Partnership or to any Partner or to any other Persons who acquired an interest in a Partnership Interest for its good faith reliance on the provisions of this Agreement.

        (d)   Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

A-57

---

Table of Contents

        Section 7.9    Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.     

        (a)   Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. Whenever the General Partner makes a determination to refer any potential conflict of interest to the Conflicts Committee for Special Approval, seek Unitholder approval or adopt a resolution or course of action that has not received Special Approval or Unitholder approval, then the General Partner shall be entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty or obligation whatsoever to the Partnership or any Limited Partner, and the General Partner shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard or duty imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in making such determination or taking or declining to take such other action shall be permitted to do so in its sole and absolute discretion. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if the Board of Directors of the General Partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above or that a director satisfies the eligibility requirements to be a member of the Conflicts Committee, then it shall be presumed that, in making its decision, the Board of Directors of the General Partner acted in good faith. It shall be presumed that in determining that a director satisfies the eligibility requirements to be a member of the Conflicts Committee, the Board of Directors of the General Partner or such Person making such a determination acted in good faith. In any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging any action by the Conflicts Committee with respect to any matter referred to the Conflicts Committee for Special Approval by the General Partner, any determination by the Board of Directors of the General Partner that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above or any determination by the Board of Directors of the General Partner that a director satisfies the eligibility requirements to be a member of the Conflicts Committee, the Person bringing or prosecuting such proceeding shall have the burden of overcoming the presumption that the Conflicts Committee or the Board of Directors of the General Partner, as applicable, acted in good faith. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the IPO Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement or any such duty.

        (b)   Whenever the General Partner or the Board of Directors, or any committee thereof (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any Affiliate of the General Partner causes the General Partner to do so, in its capacity as the general

A-58

---

Table of Contents

partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, the Board of Directors or such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards (including fiduciary standards) imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A determination or other action or inaction will conclusively be deemed to be in "good faith" for all purposes of this Agreement, if the Person or Persons making such determination or taking or declining to take such other action subjectively believe that the determination or other action or inaction is in the best interests of the Partnership Group.

        (c)   Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty or obligation whatsoever to the Partnership or any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the Person or Persons making such determination or taking or declining to take such other action shall be permitted to do so in their sole and absolute discretion. By way of illustration and not of limitation, whenever the phrase, "the General Partner at its option," or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.

        (d)   The General Partner's organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner's general partner, if the General Partner is a partnership.

        (e)   Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

        (f)    Except as expressly set forth in this Agreement or required by the Delaware Act, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

        (g)   The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing

A-59

---

Table of Contents

member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

        Section 7.10    Other Matters Concerning the General Partner.     

        (a)   The General Partner and any other Indemnitee may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

        (b)   The General Partner and any other Indemnitee may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner or such Indemnitee, respectively, reasonably believes to be within such Person's professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

        (c)   The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any other Group Member.

        Section 7.11    Purchase or Sale of Partnership Interests.     The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests or Derivative Partnership Interests; provided that, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Interests are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Articles IV and X.

        Section 7.12    Registration Rights of the General Partner and its Affiliates.     

        (a)    Demand Registration.     Upon receipt of a Notice from any Holder at any time after the 180th day after the Closing Date, the Partnership shall file with the Commission as promptly as reasonably practicable a registration statement under the Securities Act (each, a "Registration Statement") providing for the resale of the Registrable Securities, which may, at the option of the Holder giving such Notice, be a Registration Statement that provides for the resale of the Registrable Securities from time to time pursuant to Rule 415 under the Securities Act. The Partnership shall not be required pursuant to this Section 7.12(a) to file more than one Registration Statement in any twelve-month period nor to file more than three Registration Statements in the aggregate. The Partnership shall use commercially reasonable efforts to cause such Registration Statement to become effective as soon as reasonably practicable after the initial filing of the Registration Statement and to remain effective and available for the resale of the Registrable Securities by the Selling Holders named therein until the earlier of (i) six months following such Registration Statement's effective date and (ii) the date on which all Registrable Securities covered by such Registration Statement have been sold. In the event one or more Holders request in a Notice to dispose of an aggregate of at least [            ] Registrable Securities pursuant to a Registration Statement in an Underwritten Offering, the Partnership shall retain underwriters that are reasonably acceptable to such Selling Holders in order to permit such Selling Holders to effect such disposition through an Underwritten Offering; provided, however, that the Partnership shall have the exclusive right to select the bookrunning managers. The Partnership and such Selling Holders shall enter into an underwriting agreement in customary form that is reasonably acceptable to the Partnership and take all reasonable actions as are requested by the managing underwriters to facilitate the Underwritten Offering and sale of Registrable Securities

A-60

---

Table of Contents

therein. No Holder may participate in the Underwritten Offering unless it agrees to sell its Registrable Securities covered by the Registration Statement on the terms and conditions of the underwriting agreement and completes and delivers all necessary documents and information reasonably required under the terms of such underwriting agreement. In the event that the managing underwriter of such Underwritten Offering advises the Partnership and the Holder in writing that in its opinion the inclusion of all or some Registrable Securities would adversely and materially affect the timing or success of the Underwritten Offering, the amount of Registrable Securities that each Selling Holder requested be included in such Underwritten Offering shall be reduced on a Pro Rata basis to the aggregate amount that the managing underwriter deems will not have such material and adverse effect. Any Holder may withdraw from such Underwritten Offering by notice to the Partnership and the managing underwriter; provided such notice is delivered prior to the launch of such Underwritten Offering.

        (b)    Piggyback Registration.     At any time after the 180th day after the Closing Date, if the Partnership shall propose to file a Registration Statement (other than pursuant to a demand made pursuant to Section 7.12(a)) for an offering of Partnership Interests for cash (other than an offering relating solely to an employee benefit plan, an offering relating to a transaction on Form S-4 or an offering on any registration statement that does not permit secondary sales), the Partnership shall notify all Holders of such proposal at least five business days before the proposed filing date. The Partnership shall use commercially reasonable efforts to include such number of Registrable Securities held by any Holder in such Registration Statement as each Holder shall request in a Notice received by the Partnership within two business days of such Holder's receipt of the notice from the Partnership. If the Registration Statement about which the Partnership gives notice under this Section 7.12(b) is for an Underwritten Offering, then any Holder's ability to include its desired amount of Registrable Securities in such Registration Statement shall be conditioned on such Holder's inclusion of all such Registrable Securities in the Underwritten Offering; provided that, in the event that the managing underwriter of such Underwritten Offering advises the Partnership and the Holder in writing that in its opinion the inclusion of all or some Registrable Securities would adversely and materially affect the timing or success of the Underwritten Offering, the amount of Registrable Securities that each Selling Holder requested be included in such Underwritten Offering shall be reduced on a Pro Rata basis to the aggregate amount that the managing underwriter deems will not have such material and adverse effect. In connection with any such Underwritten Offering, the Partnership and the Selling Holders involved shall enter into an underwriting agreement in customary form that is reasonably acceptable to the Partnership and take all reasonable actions as are requested by the managing underwriters to facilitate the Underwritten Offering and sale of Registrable Securities therein. No Holder may participate in the Underwritten Offering unless it agrees to sells its Registrable Securities covered by the Registration Statement on the terms and conditions of the underwriting agreement and completes and delivers all necessary documents and information reasonably required under the terms of such underwriting agreement. Any Holder may withdraw from such Underwritten Offering by notice to the Partnership and the managing underwriter; provided such notice is delivered prior to the launch of such Underwritten Offering. The Partnership shall have the right to terminate or withdraw any Registration Statement or Underwritten Offering initiated by it under this Section 7.12(b) prior to the effective date of the Registration Statement or the pricing date of the Underwritten Offering, as applicable.

        (c)    Sale Procedures.     In connection with its obligations under this Section 7.12, the Partnership shall:

          (i)  furnish to each Selling Holder (A) as far in advance as reasonably practicable before filing a Registration Statement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed (including exhibits and each document incorporated by reference therein to the extent then required by the rules and regulations of the Commission), and provide each such Selling Holder the opportunity to object to

A-61

---

Table of Contents

any information pertaining to such Selling Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder with respect to such information prior to filing a Registration Statement or supplement or amendment thereto, and (B) such number of copies of such Registration Statement and the prospectus included therein and any supplements and amendments thereto as such Persons may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities covered by such Registration Statement; provided that the Partnership will not have any obligation to provide any document pursuant to clause (B) hereof that is available on the Commission's website;

         (ii)  if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities covered by a Registration Statement under the securities or blue sky laws of such jurisdictions as the Selling Holders or, in the case of an Underwritten Offering, the managing underwriter, shall reasonably request; provided, however, that the Partnership will not be required to qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action that would subject it to general service of process in any jurisdiction where it is not then so subject;

        (iii)  promptly notify each Selling Holder and each underwriter, at any time when a prospectus is required to be delivered under the Securities Act, of (A) the filing of a Registration Statement or any prospectus or prospectus supplement to be used in connection therewith, or any amendment or supplement thereto, and, with respect to such Registration Statement or any post-effective amendment thereto, when the same has become effective; and (B) any written comments from the Commission with respect to any Registration Statement or any document incorporated by reference therein and any written request by the Commission for amendments or supplements to a Registration Statement or any prospectus or prospectus supplement thereto;

        (iv)  immediately notify each Selling Holder and each underwriter, at any time when a prospectus is required to be delivered under the Securities Act, of (A) the occurrence of any event or existence of any fact (but not a description of such event or fact) as a result of which the prospectus or prospectus supplement contained in a Registration Statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading (in the case of the prospectus contained therein, in the light of the circumstances under which a statement is made); (B) the issuance or threat of issuance by the Commission of any stop order suspending the effectiveness of a Registration Statement, or the initiation of any proceedings for that purpose; or (C) the receipt by the Partnership of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction. Following the provision of such notice, subject to Section 7.12(f), the Partnership agrees to, as promptly as practicable, amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing and to take such other reasonable action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto; and

         (v)  enter into customary agreements and take such other actions as are reasonably requested by the Selling Holders or the underwriters, if any, in order to expedite or facilitate the disposition of the Registrable Securities, including the provision of comfort letters and legal opinions as are customary in such securities offerings.

        (d)    Suspension.     Each Selling Holder, upon receipt of notice from the Partnership of the happening of any event of the kind described in Section 7.12(c)(iv), shall forthwith discontinue disposition of the Registrable Securities by means of a prospectus or prospectus supplement until such

A-62

---

Table of Contents

Selling Holder's receipt of the copies of the supplemented or amended prospectus contemplated by such subsection or until it is advised in writing by the Partnership that the use of the prospectus may be resumed, and has received copies of any additional or supplemental filings incorporated by reference in the prospectus.

        (e)    Expenses.     Except as set forth in an underwriting agreement for the applicable Underwritten Offering or as otherwise agreed between a Selling Holder and the Partnership, all costs and expenses of a Registration Statement filed or an Underwritten Offering that includes Registrable Securities pursuant to this Section 7.12 (other than underwriting discounts and commissions on Registrable Securities and fees and expenses of counsel and advisors to Selling Holders) shall be paid by the Partnership.

        (f)    Delay Right.     Notwithstanding anything to the contrary herein, if the General Partner determines that the Partnership's compliance with its obligations in this Section 7.12 would be detrimental to the Partnership because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone compliance with such obligations for a period of not more than six months; provided that such right may not be exercised more than twice in any 24-month period.

        (g)    Indemnification.     

          (i)  In addition to and not in limitation of the Partnership's obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless each Selling Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, "Indemnified Persons") from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(g) as a "claim" and in the plural as "claims") based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any Registration Statement, preliminary prospectus, final prospectus or issuer free writing prospectus under which any Registrable Securities were registered or sold under the Securities Act, or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such Registration Statement, preliminary prospectus, final prospectus or issuer free writing prospectus in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

         (ii)  Each Selling Holder shall, to the fullest extent permitted by law, indemnify and hold harmless the Partnership, the General Partner, the General Partner's officers and directors and each Person who controls the Partnership or the General Partner (within the meaning of the Securities Act) and any agent thereof to the same extent as the foregoing indemnity from the Partnership to the Selling Holders, but only with respect to information regarding such Selling Holder furnished in writing by or on behalf of such Selling Holder expressly for inclusion in a Registration Statement, prospectus or free writing prospectus relating to the Registrable Securities held by such Selling Holder.

A-63

---

Table of Contents

        (iii)  The provisions of this Section 7.12(g) shall be in addition to any other rights to indemnification or contribution that a Person entitled to indemnification under this Section 7.12(g) may have pursuant to law, equity, contract or otherwise.

        (h)    Specific Performance.     Damages in the event of breach of Section 7.12 by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each party, in addition to and without limiting any other remedy or right it may have, will have the right to seek an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives, to the fullest extent permitted by the law, any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such party from pursuing any other rights and remedies at law or in equity that such party may have.

        Section 7.13    Reliance by Third Parties.     Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership's sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII.
BOOKS, RECORDS, ACCOUNTING AND REPORTS

        Section 8.1    Records and Accounting.     The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership's business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.3(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the register of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to

A-64

---

Table of Contents

account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

        Section 8.2    Fiscal Year.     The fiscal year of the Partnership shall be a fiscal year ending December 31.

        Section 8.3    Reports.     

        (a)   Whether or not the Partnership is subject to the requirement to file reports with the Commission, as soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership (or such shorter period as required by the Commission), the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership's or the Commission's website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner, and such other information as may be required by applicable law, regulation or rule of the Commission or any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

        (b)   Whether or not the Partnership is subject to the requirement to file reports with the Commission, as soon as practicable, but in no event later than 50 days after the close of each Quarter (or such shorter period as required by the Commission) except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership's or the Commission's website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of the Commission or any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX.
TAX MATTERS

        Section 9.1    Tax Returns and Information.     The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or year that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership's taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

        Section 9.2    Tax Elections.     

        (a)   The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner's determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest

A-65

---

Table of Contents

will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.

        (b)   Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

        Section 9.3    Tax Controversies.     Subject to the provisions hereof, the General Partner is designated as the "tax matters partner" (as defined in Section 6231(a)(7) of the Code) and is authorized and required to represent the Partnership (at the Partnership's expense) in connection with all examinations of the Partnership's affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

        Section 9.4    Withholding.     Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code, or established under any foreign law. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 or Section 12.4(c) in the amount of such withholding from such Partner.

ARTICLE X.
ADMISSION OF PARTNERS

        Section 10.1    Admission of Limited Partners.     

        (a)   Upon the issuance by the Partnership of Common Units, Subordinated Units and Incentive Distribution Rights to the General Partner, Summit Midstream Partners, LLC and the IPO Underwriters in connection with the Initial Public Offering as described in Article V, such Persons shall, by acceptance of such Partnership Interests, and upon becoming the Record Holders of such Partnership Interests, be admitted to the Partnership as Initial Limited Partners in respect of the Common Units, Subordinated Units or Incentive Distribution Rights issued to them and be bound by this Agreement, all with or without execution of this Agreement by such Persons.

        (b)   By acceptance of any Limited Partner Interests transferred in accordance with Article IV or acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger, consolidation or conversion pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee, agent or representative acquiring such Limited Partner Interests for the account of another Person or Group, who shall be subject to Section 10.1(c) below) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when such Person becomes the Record Holder of the Limited Partner Interests so transferred or acquired, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) shall be deemed to represent that the transferee or acquirer has the capacity, power and authority to enter into this Agreement, (iv) shall be deemed to make any consents, acknowledgements or waivers contained in this Agreement and (v) shall be deemed to certify that the transferee or acquirer is not an Ineligible Holder, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner

A-66

---

Table of Contents

without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and becoming the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.9.

        (c)   With respect to any Limited Partner that holds Units representing Limited Partner Interests for another Person's account (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such Limited Partner shall, in exercising the rights of a Limited Partner in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, take all action as a Limited Partner by virtue of being the Record Holder of such Units at the direction of the Person who is the beneficial owner, and the Partnership shall be entitled to assume such Limited Partner is so acting without further inquiry.

        (d)   The name and mailing address of each Record Holder shall be listed on the books of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable).

        (e)   Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b).

        Section 10.2    Admission of Successor General Partner.     A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor is hereby authorized to and shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

        Section 10.3    Amendment of Agreement and Certificate of Limited Partnership.     To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI.
WITHDRAWAL OR REMOVAL OF PARTNERS

        Section 11.1    Withdrawal of the General Partner.     

        (a)   The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an "Event of Withdrawal");

          (i)  The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

         (ii)  The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;

        (iii)  The General Partner is removed pursuant to Section 11.2;

A-67

---

Table of Contents

        (iv)  The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A) through (C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

         (v)  A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

        (vi)  (A) if the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) if the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) if the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise upon the termination of the General Partner.

        If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

        (b)   Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Time, on                        , 2022 the General Partner voluntarily withdraws by giving at least 90 days' advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel ("Withdrawal Opinion of Counsel") that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Time, on                        , 2022 the General Partner voluntarily withdraws by giving at least 90 days' advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days' advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The

A-68

---

Table of Contents

Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner's withdrawal, a successor is not elected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

        Section 11.2    Removal of the General Partner.     The General Partner may be removed if such removal is approved by the Unitholders holding at least 66²/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units voting as a class and Unitholders holding a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

        Section 11.3    Interest of Departing General Partner and Successor General Partner.     

        (a)   In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates' general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates' Incentive Distribution Rights (collectively, the "Combined Interest") in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the

A-69

---

Table of Contents

Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

        For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner's withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner's successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership's assets, the rights and obligations of the Departing General Partner, the value of the Incentive Distribution Rights and the General Partner Interest and other factors it may deem relevant.

        (b)   If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

        (c)   If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership's assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner's admission, the successor General Partner's interest in all Partnership distributions and allocations shall be its Percentage Interest.

        Section 11.4    Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.     Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are

A-70

---

Table of Contents

not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis, (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest and its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor in accordance with Section 11.3.

        Section 11.5    Withdrawal of Limited Partners.     No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner's Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII.
DISSOLUTION AND LIQUIDATION

        Section 12.1    Dissolution.     The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, Section 11.2 or Section 12.2, to the fullest extent permitted by law, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

        (a)   an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and a Withdrawal Opinion of Counsel is received as provided in Section 11.1(b) or 11.2 and such successor is admitted to the Partnership pursuant to Section 10.2;

        (b)   an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

        (c)   the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

        (d)   at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

        Section 12.2    Continuation of the Business of the Partnership After Dissolution.     Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then, to the maximum extent permitted by law, within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

        (i)    the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

A-71

---

Table of Contents

        (ii)   if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

        (iii)  the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner under the Delaware Act and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

        Section 12.3    Liquidator.     Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days' prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

        Section 12.4    Liquidation.     The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

        (a)   The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership's assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership's assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership's assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

        (b)   Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than

A-72

---

Table of Contents

in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

        (c)   All property and all cash in excess of that required to satisfy liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

        Section 12.5    Cancellation of Certificate of Limited Partnership.     Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

        Section 12.6    Return of Contributions.     The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

        Section 12.7    Waiver of Partition.     To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

        Section 12.8    Capital Account Restoration.     No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII.
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

        Section 13.1    Amendments to be Adopted Solely by the General Partner.     Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

        (a)   a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

        (b)   admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

        (c)   a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

A-73

---

Table of Contents

        (d)   a change that the General Partner determines, (i) does not adversely affect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests in any material respect (except as permitted by subsection (g) of this Section 13.1), (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the IPO Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

        (e)   a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of "Quarter" and the dates on which distributions are to be made by the Partnership;

        (f)    an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

        (g)   an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization or issuance of any class or series of Partnership Interests pursuant to Section 5.6;

        (h)   any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

        (i)    an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 14.3;

        (j)    an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

        (k)   a merger, conveyance or conversion pursuant to Section 14.3(e); or

        (l)    any other amendments substantially similar to the foregoing.

        Section 13.2    Amendment Procedures.     Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so free of any duty or obligation whatsoever to the Partnership, any Limited Partner or any other Person bound by this Agreement, and, in declining to propose or approve an amendment to this Agreement, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to propose or approve any amendment to this Agreement shall be permitted to do so in its sole and absolute discretion. An amendment to this Agreement shall

A-74

---

Table of Contents

be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or Section 13.3, the holders of a Unit Majority, unless a greater or different percentage of Outstanding Units is required under this Agreement. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has posted or made accessible such amendment through the Partnership's or the Commission's website.

        Section 13.3    Amendment Requirements.     

        (a)   Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of (i) in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage or (ii) in the case of Section 11.2 or Section 13.4, increasing such percentages, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute (x) in the case of a reduction as described in subclause (a)(i) hereof, not less than the voting requirement sought to be reduced, (y) in the case of an increase in the percentage in Section 11.2, not less than 90% of the Outstanding Units, or (z) in the case of an increase in the percentage in Section 13.4, not less than a majority of the Outstanding Units.

        (b)   Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c) or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

        (c)   Except as provided in Section 14.3, and without limitation of the General Partner's authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

        (d)   Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(c), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

        (e)   Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

        Section 13.4    Special Meetings.     All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the specific purposes for which the special meeting is to be called and the class or classes of Units for which the meeting is proposed.

A-75

---

Table of Contents

No business may be brought by any Limited Partner before such special meeting except the business listed in the related request. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send or cause to be sent a notice of the meeting to the Limited Partners. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not be permitted to vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners' limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business. If any such vote were to take place, to the fullest extent permitted by law, it shall be deemed null and void to the extent necessary so as not to jeopardize the Limited Partners' limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

        Section 13.5    Notice of a Meeting.     Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1.

        Section 13.6    Record Date.     For purposes of determining the Limited Partners who are Record Holders of the class or classes of Limited Partner Interests entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11, the General Partner shall set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which such Limited Partners are requested in writing by the General Partner to give such approvals.

        Section 13.7    Postponement and Adjournment.     Prior to the date upon which any meeting of Limited Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be fixed unless such postponement shall be for more than 45 days. Any meeting of Limited Partners may be adjourned by the General Partner one or more times for any reason, including the failure of a quorum to be present at the meeting with respect to any proposal or the failure of any proposal to receive sufficient votes for approval. No Limited Partner vote shall be required for any adjournment. A meeting of Limited Partners may be adjourned by the General Partner as to one or more proposals regardless of whether action has been taken on other matters. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

        Section 13.8    Waiver of Notice; Approval of Meeting.     The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy.

A-76

---

Table of Contents

Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove of any matters submitted for consideration or to object to the failure to submit for consideration any matters required to be included in the notice of the meeting, but not so included, if such objection is expressly made at the beginning of the meeting.

        Section 13.9    Quorum and Voting.     The presence, in person or by proxy, of holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote at such meeting shall be deemed to constitute the act of all Limited Partners, unless a different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the exit of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement.

        Section 13.10    Conduct of a Meeting.     The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The Chairman of the Board shall serve as Chairman of any meeting, or if none, the General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the submission and revocation of approvals in writing.

        Section 13.11    Action Without a Meeting.     If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Outstanding Units held by such Limited Partners, the Partnership shall be deemed to have failed

A-77

---

Table of Contents

to receive a ballot for the Outstanding Units that were not voted. If approval of the taking of any permitted action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) approvals sufficient to take the action proposed are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are first deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners' limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

        Section 13.12    Right to Vote and Related Matters.     

        (a)   Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of "Outstanding") shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

        (b)   With respect to Units that are held for a Person's account by another Person that is the Record Holder (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), such Record Holder shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume such Record Holder is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

        Section 13.13    Voting of Incentive Distribution Rights.     Notwithstanding anything in this Agreement to the contrary, the Record Holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter.

ARTICLE XIV.
MERGER, CONSOLIDATION OR CONVERSION

        Section 14.1    Authority.     The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America or any other country, pursuant to a written plan of merger or consolidation ("Merger Agreement") or a written plan of conversion ("Plan of Conversion"), as the case may be, in accordance with this Article XIV.

        Section 14.2    Procedure for Merger, Consolidation or Conversion.     

        (a)   Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to consent to a merger, consolidation or

A-78

---

Table of Contents

conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to consent to any merger, consolidation or conversion of the Partnership shall be permitted to do so in its sole and absolute discretion.

        (b)   If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

          (i)  name and state or country of domicile of each of the business entities proposing to merge or consolidate;

         (ii)  the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the "Surviving Business Entity");

        (iii)  the terms and conditions of the proposed merger or consolidation;

        (iv)  the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (A) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

         (v)  a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

        (vi)  the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

       (vii)  such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

        (c)   If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

          (i)  the name of the converting entity and the converted entity;

         (ii)  a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

        (iii)  a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

A-79

---

Table of Contents

        (iv)  the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity;

         (v)  in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

        (vi)  in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

       (vii)  the effective time of the conversion, which may be the date of the filing of the certificate of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

      (viii)  such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

        Section 14.3    Approval by Limited Partners.     

        (a)   Except as provided in Section 14.3(e), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent and, subject to any applicable requirements of Regulation 14A pursuant to the Exchange Act or successor provision, no other disclosure regarding the proposed merger, consolidation or conversion shall be required.

        (b)   Except as provided in Section 14.3(e) and Section 14.3(f), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, effects an amendment to any provision of this Agreement that, if contained in an amendment to this Agreement adopted pursuant to Article XIII, would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

        (c)   Except as provided in Section 14.3(e) and Section 14.3(f), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or articles of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

        (d)   Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any other Group Member into a new limited liability entity, to merge the Partnership or any other Group Member into, or convey all of the Partnership's assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of limited liability under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) of any Limited Partner as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent

A-80

---

Table of Contents

not previously treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

        (e)   Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another limited liability entity if (i) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (iii) the Partnership is the Surviving Business Entity in such merger or consolidation, (iv) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (v) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests (other than Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.

        (f)    Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (i) effect any amendment to this Agreement or (ii) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

        Section 14.4    Certificate of Merger or Certificate of Conversion.     Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion or other filing, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware or the appropriate filing office of any other jurisdiction, as applicable, in conformity with the requirements of the Delaware Act or other applicable law.

        Section 14.5    Effect of Merger, Consolidation or Conversion.     

        (a)   At the effective time of the merger:

          (i)  all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

         (ii)  the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

        (iii)  all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

A-81

---

Table of Contents

        (iv)  all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

        (b)   At the effective time of the conversion:

          (i)  the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

         (ii)  all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

        (iii)  all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

        (iv)  all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

         (v)  a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior Partners without any need for substitution of parties; and

        (vi)  the Partnership Interests that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV.
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

        Section 15.1    Right to Acquire Limited Partner Interests.     

        (a)   Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three Business Days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

        (b)   If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the applicable Transfer Agent or exchange agent notice of such election to purchase (the "Notice of Election to Purchase") and shall cause the Transfer Agent or exchange agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner), together with such information as may be required by law, rule or regulation, at least 10, but not more than 60,

A-82

---

Table of Contents

days prior to the Purchase Date. Such Notice of Election to Purchase shall also be filed and distributed as may be required by the Commission or any National Securities Exchange on which such Limited Partner Interests are listed. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests, in the case of Limited Partner Interests evidenced by Certificates, or instructions agreeing to such redemption in exchange for payment, at such office or offices of the Transfer Agent or exchange agent as the Transfer Agent or exchange agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the Partnership Register shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent or exchange agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate or redemption instructions shall not have been surrendered for purchase or provided, respectively, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent or exchange agent of the Certificates representing such Limited Partner Interests, in the case of Limited Partner Interests evidenced by Certificates, or instructions agreeing to such redemption, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the Partnership Register, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the Record Holder of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the Record Holder of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).

        (c)   In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon, in accordance with procedures set forth by the General Partner.

ARTICLE XVI.
GENERAL PROVISIONS

        Section 16.1    Addresses and Notices; Written Communications.     

        (a)   Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Except as otherwise provided herein, any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown in the Partnership

A-83

---

Table of Contents

Register, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing in the Partnership Register is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

        (b)   The terms "in writing", "written communications," "written notice" and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

        Section 16.2    Further Action.     The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

        Section 16.3    Binding Effect.     This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

        Section 16.4    Integration.     This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

        Section 16.5    Creditors.     None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

        Section 16.6    Waiver.     No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

        Section 16.7    Third-Party Beneficiaries.     Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

        Section 16.8    Counterparts.     This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by

A-84

---

Table of Contents

this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) or (b) without execution hereof.

        Section 16.9    Applicable Law; Forum; Venue and Jurisdiction; Waiver of Trial by Jury.     

        (a)   This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

        (b)   Each of the Partners and each Person or Group holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

          (i)  irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

         (ii)  irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claim, suit, action or proceeding;

        (iii)  agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

        (iv)  expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and

         (v)  consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.

        Section 16.10    Invalidity of Provisions.     If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and/or parts thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provisions and/or part shall be reformed so that it would be valid, legal and enforceable to the maximum extent possible.

        Section 16.11    Consent of Partners.     Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

A-85

---

Table of Contents

        Section 16.12    Facsimile and Email Signatures.     The use of facsimile signatures and signatures delivered by email in portable document format (.pdf) affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

A-86

---

Table of Contents

        IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

   

Signature Page to First Amended and Restated
Agreement of Limited Partnership of Summit Midstream Partners, LP

A-87

---

Table of Contents

EXHIBIT A
to the First Amended and Restated
Agreement of Limited Partnership of
Summit Midstream Partners, LP

Certificate Evidencing Common Units
Representing Limited Partner Interests in
Summit Midstream Partners, LP

No. Common Units

        In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, as amended, supplemented or restated from time to time (the "Partnership Agreement"), Summit Midstream Partners, LP, a Delaware limited partnership (the "Partnership"), hereby certifies that                        (the "Holder") is the registered owner of Common Units representing limited partner interests in the Partnership (the "Common Units") transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2100 McKinney Avenue, Suite 1250, Dallas, Texas 75201. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

        THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF SUMMIT MIDSTREAM PARTNERS, LP THAT THIS SECURITY MAY NOT BE TRANSFERRED IF SUCH TRANSFER (AS DEFINED IN THE PARTNERSHIP AGREEMENT) WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF SUMMIT MIDSTREAM PARTNERS, LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE SUMMIT MIDSTREAM PARTNERS, LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). THE GENERAL PARTNER OF SUMMIT MIDSTREAM PARTNERS, LP MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF SUMMIT MIDSTREAM PARTNERS, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THIS SECURITY MAY BE SUBJECT TO ADDITIONAL RESTRICTIONS ON ITS TRANSFER PROVIDED IN THE PARTNERSHIP AGREEMENT. COPIES OF SUCH AGREEMENT MAY BE OBTAINED AT NO COST BY WRITTEN REQUEST MADE BY THE HOLDER OF RECORD OF THIS SECURITY TO THE SECRETARY OF THE GENERAL PARTNER AT THE PRINCIPAL EXECUTIVE OFFICES OF THE PARTNERSHIP. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

        The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have

A-A-1

---

Table of Contents

executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, and (iii) made the waivers and given the consents and approvals contained in the Partnership Agreement.

        This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.

A-A-2

---

Table of Contents

[Reverse of Certificate]

ABBREVIATIONS

        The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

A-A-3

---

Table of Contents

ASSIGNMENT OF COMMON UNITS OF
SUMMIT MIDSTREAM PARTNERS, LP

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto

        Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of Summit Midstream Partners, LP.

        No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

A-A-4

---

Table of Contents

APPENDIX B
GLOSSARY OF TERMS

        AMI:     Area of mutual interest.

        condensate:     A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

        dry gas:     A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

        end users:     The ultimate users and consumers of transported energy products.

        Mcf:     One thousand cubic feet.

        MMBtu:     One million British Thermal Units.

        MMBtu/d:     One million British Thermal Units per day.

        MMcf:     One million cubic feet.

        MMcf/d:     One million cubic feet per day.

        MVC:     Minimum volume commitment.

        NGLs:     Natural gas liquids. The combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

        NYMEX:     New York Mercantile Exchange.

        play:     A proven geological formation that contains commercial amounts of hydrocarbons.

        receipt point:     The point where production is received by or into a gathering system or transportation pipeline.

        residue gas:     The natural gas remaining after being processed or treated.

        tailgate:     Refers to the point at which processed natural gas and natural gas liquids leave a processing facility for end-use markets.

        Tcf:     One trillion cubic feet.

        throughput volume:     The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

        wellhead:     The equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.

B-1

---

Table of Contents

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

---

Prospectus

                         , 2012

---

Barclays

BofA Merrill Lynch

Goldman, Sachs & Co.

Morgan Stanley

        Until                    , 2012 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

---

Table of Contents

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        Set forth below are the expenses (other than underwriting discounts, commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

Item 14.    Indemnification of Directors and Officers.

Summit Midstream Partners, LP

        Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

        The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Summit Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Summit Midstream GP, LLC

        Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

        Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

II-1

---

Table of Contents

•

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;



•

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and



•

any person designated by our general partner.

        Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15.    Recent Sales of Unregistered Securities.

        On May 10, 2012, in connection with the formation of Summit Midstream Partners LP, we issued (i) the 2.0% general partner interest in us to Summit Midstream GP, LLC for $20, and (ii) a 98% limited partner interest in us to Summit Midstream Partners, LLC for $980, in each case in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

Item 16.    Exhibits and Financial Schedules.

        The following documents are filed as exhibits to this registration statement:

II-2

---

Table of Contents

Item 17.    Undertakings

        The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

        Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

        The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.



(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3

---

Table of Contents

(3)

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.



(4)

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

          (i)  Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

         (ii)  If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use;

        (iii)  Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

        (iv)  The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

         (v)  Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

        The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Summit Midstream GP, LLC our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Summit Midstream GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

        The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-4

---

Table of Contents

SIGNATURES

        Pursuant to the to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on August 21, 2012.

        Each person whose signature appears below appoints Steven J. Newby and Brock M. Degeyter, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

II-5

---

Table of Contents

        Pursuant to the requirements of the Securities Act of 1933, as amended this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

II-6

---

Table of Contents

EXHIBIT INDEX

        The following documents are filed as exhibits to this registration statement:

---

Exhibit 99.1

         As filed with the Securities and Exchange Commission on May 11, 2012

Registration No. 333-                        

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Summit Midstream Partners, LP
(Exact Name of Registrant as Specified in its Charter)

2100 McKinney Avenue
Suite 1250
Dallas, Texas 75201
(214) 242-1955
(Address, including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

Brock M. Degeyter
Senior Vice President and General Counsel
2100 McKinney Avenue
Suite 1250
Dallas, TX 75201
(214) 242-1955
(Name, Address, including Zip Code, and Telephone Number, including
Area Code, of Agent for Service)

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

         If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

         If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

         If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

         If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

CALCULATION OF REGISTRATION FEE

(1)

Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   

---

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated May 11, 2012

PROSPECTUS

---

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

---

This is the initial public offering of our common units representing limited partner interests. We are offering             common units in this offering. We currently expect that the initial public offering price will be between $             and $             per common unit. Prior to this offering, there has been no public market for our common units.

We intend to apply to list our common units on the New York Stock Exchange under the symbol "SMLP."

We are an "emerging growth company" as defined in Section 101 of the Jumpstart Our Business Startups Act, or JOBS Act.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 16.

These risks include the following:

•

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.



•

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.



•

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.



•

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to our unitholders over the long-term.



•

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.



•

Summit Midstream Partners, LLC, which we refer to as "Summit Investments," owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Summit Investments and our general partner have conflicts of interest with us and limited fiduciary duties, and Summit Investments and our general partner may favor their interests to the detriment of us and our other unitholders.



•

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.



•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.



•

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.



•

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

We have granted the underwriters the option to purchase up to an additional             common units on the same terms and conditions set forth above if the underwriters sell more than              common units in this offering.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about                    , 2012, through the book-entry facilities of The Depository Trust Company.

---

Barclays

---

Prospectus dated                    , 2012

---

[Inside Front Cover Art]

---

      

TABLE OF CONTENTS

i

---

ii

---

        You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making

iii

---

an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

Industry and Market Data

        The data included in this prospectus regarding the midstream natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management's knowledge and experience in the industry in which we operate. Although we believe the third-party sources are reliable and that the third-party information used in this prospectus or in our estimates is accurate and complete, we have not independently verified the information, nor have we ascertained the economic assumptions underlying such information.

iv

---

      

1

---

 

2

---

 

3

---

 

4

---

 

5

---

 

6

---

 

7

---

      

8

---

 

9

---

     

10

---

 

11

---

 

12

---

 

13

---

14

---

 

15

---

RISK FACTORS

        Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were to materialize, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.

        In order to pay the minimum quarterly distribution of $            per unit per quarter, or $            per unit on an annualized basis, we will require available cash of approximately $             million per quarter, or $             million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the volume of natural gas we gather and compress;



•

the level of production of natural gas from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, natural gas and natural gas liquids, or NGLs;



•

damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism;



•

leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise;



•

changes in the fees we charge for our services;



•

the level of competition from other midstream energy companies in our geographic markets;



•

changes in the level of our operating, maintenance and general and administrative costs;



•

regulatory action affecting the supply of, or demand for, natural gas, the fees we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and



•

prevailing economic and market conditions.

        In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

•

the level and timing of capital expenditures we make;



•

the level of our operating and general and administrative expenses, including reimbursements to our general partner for services provided to us;



•

the cost of acquisitions, if any;



•

our debt service requirements and other liabilities;

16

---

•

fluctuations in our working capital needs;



•

our ability to borrow funds and access capital markets;



•

restrictions contained in our debt agreements;



•

the amount of cash reserves established by our general partner; and



•

other business risks affecting our cash levels.

        For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011.

        We must generate approximately $             million of available cash to pay the minimum quarterly distribution for four quarters on all of our common and subordinated units that will be outstanding immediately following this offering, as well as the corresponding distribution on our 2.0% general partner interest. The amount of cash available for distribution that we generated during the year ended December 31, 2011 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common and subordinated units as well as the corresponding distribution on our 2.0% general partner interest for that period. Specifically, the amount of cash available for distribution that we generated during the year ended December 31, 2011 would have been sufficient to pay a distribution of $            per common unit per quarter ($            per common unit on an annualized basis) and we would not have been able to pay any distributions on our subordinated units for that period. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Our Cash Distribution Policy and Restrictions on Distributions."

The assumptions underlying the forecast of cash available for distribution that we include in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending June 30, 2013. We estimate that our total cash available for distribution for the twelve months ending June 30, 2013 will be approximately $79.7 million, as compared to approximately $32.0 million for the year ended December 31, 2011 on a historical as adjusted basis. The significant expected increase in cash available for distribution is primarily attributable to the inclusion of the Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011. To the extent that volumes on either the Grand River system or the DFW Midstream system are lower than we project, our revenues during the forecast period will be adversely affected. If the actual volume of natural gas we gather on our systems for the twelve months ending June 30, 2013 is 10% lower than our forecast, we expect we would have sufficient cash available to pay the full distribution to holders of our common units and only        % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

17

---

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.

        A significant percentage of our revenue is attributable to a relatively small number of customers. Chesapeake, Carrizo Oil & Gas, Inc. and TOTAL accounted for approximately 34%, 17% and 10%, respectively, of our revenue for the year ended December 31, 2011. Going forward, Encana will be a major customer on our Grand River system and will likely account for a substantial portion of our revenues. If our customers curtail or reduce production in our areas of operation it could reduce throughput on our system and, therefore, adversely affect our revenues, cash flow and ability to make distributions to our unitholders. For example, in January 2012 Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region as well as reduce its dry gas production by up to 500 Bcf/d. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011 primarily as a result of Chesapeake's publicly announced reduction in production. Please read "—Our gas gathering agreements contain provisions that may not work as intended, and as a result they may reduce a customer's minimum volume commitment period or the intended cash flow stability."

        Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenue and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue. In addition, if any one or more of our gas gathering agreements that account for 25% or more of our revenues are terminated, and such termination is reasonably expected to have a Material Adverse Effect (as defined in our amended and restated revolving credit facility), and a replacement agreement is not obtained within 30 days, this would constitute an event of default under our amended and restated revolving credit facility and our lenders would be able to accelerate payment of the debt outstanding thereunder.

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

        Our operations are focused on natural gas gathering and compression services. Our assets are located exclusively in the Piceance Basin in western Colorado and the Barnett Shale region in north-central Texas and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of industrial and geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. For example, a significant portion of the gas we gather in the Piceance Basin and the Barnett Shale is dry gas. Due to recent declines in natural gas prices, several of our customers have substantially reduced their dry gas production in these regions and announced their intent to reduce capital expenditures for dry gas drilling activities.

        A significant portion of our operations are concentrated in the Barnett Shale region, which could disproportionately expose us to operational and regulatory risk in that area. The location of the Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with

18

---

drilling for natural gas in urban and suburban communities. The DFW Midstream system is within the city limits of various municipalities in that region, including Arlington, Texas. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs, which has led producers to pursue a high density pad site drilling strategy. Furthermore, the process of obtaining permits for constructing additional gathering lines to deliver our customers' natural gas to market may be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to you over the long-term.

        Lower natural gas prices over the long-term could result in a decline in the production of natural gas resulting in reduced throughput on our systems. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $2.13 per MMBtu as of March 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration, the EIA, average annual natural gas production in the United States increased 14.1% from 55.3 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 1.6 Tcf as of March 31, 2011 to approximately 2.5 Tcf as of March 31, 2012, due to the unseasonably warm winter of 2011/2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 635 as of March 31, 2012 according to Smith Bits (a unit of Schlumberger), as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

        The decline in natural gas prices has had a negative impact on exploration, development and production activity in our areas of operation. If natural gas prices remain depressed or decrease further, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        Also, higher natural gas prices over the long-term could result in a decline in the demand for natural gas and, therefore, in the throughput on our systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.

        The natural gas volumes that support our business depend on the level of production from natural gas wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas

19

---

include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.

        We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

•

the availability and cost of capital;



•

prevailing and projected commodity prices, including the prices of oil, natural gas and NGLs;



•

demand for oil, natural gas and NGLs;



•

levels of reserves;



•

geological considerations;



•

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and



•

the availability of drilling rigs and other costs of production and equipment.

        Fluctuations in energy prices can also greatly affect the development of new oil and natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas, or LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Recent declines in natural gas prices have had a negative impact on exploration, development and production activity and, if sustained, could lead to further decreases in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.

        Many of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experience a reduction in throughput, which would result in a decline in our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

        Because of these and other factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those

20

---

reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

If our customers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.

        If we are not successful in attracting new customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from our existing customers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements, our customers are not obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in January 2012, Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region and to reduce its total dry gas production by up to 500 Bcf/d. Similarly, in February 2012, Encana announced its intent to reduce its dry gas production to approximately 3.1 Bcf/d, a decrease of approximately 250 MMcf/d from 2011 levels. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011, primarily as a result of Chesapeake's publicly announced reduction in production. Encana's public announcement has not impacted the volume on our Grand River system but may do so in the future. Any further reductions by Chesapeake or our other customers in our areas of operation could result in further reductions in throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

        Our gas gathering agreements were designed to generate stable cash flows to us over the long term. The primary mechanism on which we rely to generate our stable cash flows is an annual minimum volume commitment, or MVC, from our customers. Under these annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, the majority of our gas gathering agreements also include an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering system (or an equivalent monetary amount) over the MVC term. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent years exceed its MVC. In such a situation, we would not receive gathering fees on throughput in excess of a customer's annual MVC to the extent that the customer had made a shortfall payment with respect to one or more preceding contract years.



•

To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped excess natural gas on our DFW Midstream system relative to its

21

---

MVC. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.

•

To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in future periods, subject to expiration in the event that there is no shortfall in subsequent periods. In such a situation, we would receive lower gathering fees in a particular contract year than we would otherwise be entitled to receive under the customer's MVC.

        Under certain circumstances, some or all of these provisions can apply in combination with one another. It is possible that the combined effect of these mechanisms could result in our receiving no revenues or cash flows from one or more customers in periods where those customers are shipping volumes on our systems. In this circumstance, we would incur compression and other operating expenses with no corresponding revenues, which would exacerbate the effect of these provisions on our results of operations. In the most extreme circumstances we could:

•

incur operating expenses with no corresponding revenues from one or more significant customers for a period of up to 35 months; or



•

all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregate MVCs have been satisfied with previous throughput volume shipments.

If either of these circumstances were to occur, it would have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make distributions to our unitholders.

We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

        We do not have and we do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of natural gas reserves connected to our systems, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs.

        Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

        We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our

22

---

AMIs, non-customer producers that lease acreage within one of our AMIs and produce natural gas may choose to use one of our competitors to gather that natural gas.

        In addition, our customers may develop their own gathering systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

        We gather the natural gas on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain AMIs from new customers in the future, and we may be unable to renew existing AMIs with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

•

the level of existing and new competition to provide gathering services to our markets;



•

the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;



•

the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;



•

the extent to which the customers in our markets are willing to contract on a long-term basis; and



•

the effects of federal, state or local regulations on the contracting practices of our customers.

        To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operating results.

        Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our counterparties will perform or adhere to existing or future contractual arrangements.

        The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.

        Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.

23

---

        Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash flow and our ability to make distributions to our unitholders could be adversely affected.

        Our natural gas gathering pipelines connect to other pipelines and midstream facilities, such as processing plants, owned and operated by unaffiliated third parties, such as Energy Transfer Partners, L.P., Enterprise Products Partners L.P. and others. For example, all of the volumes we currently gather on the Grand River system are delivered to Enterprise Products Partners L.P.'s processing plant in Meeker, Colorado. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenue, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

We have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and operating results.

        We purchased the substantial majority of our initial assets from Energy Future Holdings and Chesapeake in September 2009 and from Encana in October 2011. The initial members of our executive management team were hired shortly before our initial purchase from Energy Future Holdings and, consequently, have a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management team may be unaware of and that may have a material adverse effect on our business and results of operations. The steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time to connect additional wells and maintain throughput volume. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

A shortage of skilled labor in the midstream natural gas industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.

        The gathering of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner's employees, our results of operations could be materially and adversely affected.

24

---

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

        Our operations are subject to all of the risks and hazards inherent in the gathering, compressing and dehydrating of natural gas, including:

•

damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;



•

inadvertent damage from construction, vehicles, farm and utility equipment;



•

leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;



•

ruptures, fires and explosions; and



•

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

        These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. These risks may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive minimum volume commitments to customers during times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.

        Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover for potential environmental liabilities.

None of the proceeds of this offering will be used to maintain or grow our asset base or be reserved for future distributions.

        None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to cover future distributions, and none of the proceeds will be reserved for future distributions. The net proceeds of the offering will be used to repay amounts outstanding under our amended and restated revolving credit facility and to make a cash distribution to Summit Investments to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us.

25

---

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

        Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

        If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, (iii) outbid by competitors, or (iv) we are unable to obtain necessary governmental or third-party consents or for any other reason, then our future growth and ability to increase cash distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

        Any acquisition involves potential risks, including, among other things:

•

mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;



•

an inability to secure adequate customer commitments to use the acquired systems or facilities;



•

the risk that natural gas or crude oil reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;



•

an inability to integrate successfully the assets or businesses we acquire;



•

coordinating geographically disparate organizations, systems and facilities;



•

the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;



•

mistaken assumptions about the overall costs of equity or debt;



•

the diversion of management's and employees' attention from other business concerns;



•

unforeseen difficulties operating in new geographic areas and business lines; and



•

customer or key employee losses at the acquired businesses.

        If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

        One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of

26

---

significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

        For instance, as we develop our medium pressure system to serve the Niobrara Shale formation, the construction will occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

        In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way or federal and state environmental or other authorizations. The approval process for gathering activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such rights-of-way or other authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be adversely affected.

We require access to significant amounts of additional capital to implement our growth strategy, as well as to meet potential future capital requirements under certain of our gas gathering agreements. Tightened capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

        In order to expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We expect to make substantial expansion capital expenditures during the twelve months ending June 30, 2013. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gas gathering agreements may also require us to spend significant amounts of capital, including over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital we would be required to spend to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our amended and restated credit facility.

        We will be required to use cash from operations or incur borrowings or sell additional common units or other securities in order to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. If we are unable to raise expansion capital, we may lose the opportunity to

27

---

make acquisitions or to gather natural gas production from new upstream projects developed by our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

        We do not have any commitment from our sponsors or their affiliates, including Energy Capital Partners and GE Energy Financial Services, to provide any direct or indirect financial assistance to us following the closing of this offering.

Because our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

        Interest rates are generally at or near historic lows and may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

        Upon the closing of this offering, we expect to have approximately $     million of total indebtedness and $     million available for future borrowings under our amended and restated revolving credit facility. Our future level of debt could have important consequences to us, including the following:

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;



•

our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;



•

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and



•

our flexibility in responding to changing business and economic conditions may be limited.

        Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital

28

---

expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our amended and restated revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

        We recently amended and restated our revolving credit facility. As amended and restated, our revolving credit facility limits our ability to, among other things:

•

incur or guarantee additional debt;



•

make distributions on or redeem or repurchase units;



•

make certain investments and acquisitions;



•

make capital expenditures;



•

incur certain liens or permit them to exist;



•

enter into certain types of transactions with affiliates;



•

merge or consolidate with another company; and



•

transfer, sell or otherwise dispose of assets.

        Our amended and restated revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for additional information.

        The provisions of our amended and restated revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our amended and restated revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

A portion of our revenues are exposed to changes in oil and natural gas prices, and our exposure may increase in the future.

        For the year ended December 31, 2011, we generated approximately 80% of our revenues pursuant to long-term, fee-based gas gathering agreements under which we are paid based on the volumes of natural gas that we gather rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited exposure to direct commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. For example, in the future we may enter into percent-of-proceeds contracts with our customers, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of natural gas and NGLs.

        Substantially all of our remaining revenue is derived from (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with our

29

---

electric-drive compression and (ii) the sale of condensate volumes that we collect on the Grand River system. Our revenues with respect to our sale of retained natural gas are tied to the price of natural gas. In addition, changes in the price of oil could directly affect the revenues we receive fom the sale of condensate.

        Furthermore, we may acquire or develop additional midstream assets in the future, including assets related to commodities other than natural gas, that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.

A change in laws and regulations applicable to our assets or services may cause our operating and maintenance expenses to increase or revenue to decline.

        Various aspects of our operations are subject to extensive and frequently changing regulation as the activities of the natural gas industry often are reviewed by legislators and regulators. More stringent legislation or regulation or taxation of natural gas drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. Numerous federal, state and local departments and agencies are authorized by statute to issue, and have issued, rules and regulations binding upon participants in the natural gas industry. Our operations and the markets in which we participate are affected by these laws and regulations and may be affected by changes to such laws and regulations, which may cause us to incur materially increased operating costs or realize materially lower revenues or both.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

        A portion of our customers' natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers. In addition, the federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected to be available between late 2012 and 2014. On May 4, 2012, the Department of the Interior's Bureau of Land Management ("BLM") issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans. Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. The chemical ingredient information for hydraulic fracturing fluid is generally available to the public through online databases, and this may bring more public scrutiny to hydraulic fracturing operations. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines which

30

---

could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations.

We are subject to federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements, and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

        We believe that our pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of the Federal Energy Regulatory Commission, also known as FERC, under the Natural Gas Act of 1938, also known as the NGA, and the Natural Gas Policy Act of 1978, also known as the NGPA. We are, however, subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, also known as EPAct 2005, and to FERC's regulations thereunder, which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, the Federal Trade Commission, also known as FTC, holds statutory authority under the Energy Independence and Security Act of 2007, also known as the EISA, to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. FTC is also authorized to seek fines of up to one million dollars ($1,000,000) per day per violation. The Commodity Futures Trading Commission, also known as the CFTC, is directed under the Commodity Exchange Act, also known as the CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, also known as the Dodd-Frank Act, and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for each violation of the anti-market manipulation sections of the CEA.

        The distinction between federally-unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

        State and municipal regulations also affect our business. We are subject to state and local regulation regarding the construction and operation of our gathering systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of gas we may gather. Ratable take statutes and regulations generally require gatherers to take natural gas production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather. Many states have adopted complaint-based regulation of gathering activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering, including state regulation of production rates, maximum daily production allowable from gas wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs, and revenues.

31

---

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

        Our natural gas gathering, compression and dehydrating operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Examples of these laws include:

•

the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;



•

the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;



•

the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;



•

the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;



•

the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;



•

the Endangered Species Act, also known as the ESA; and



•

the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

        These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

        There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the

32

---

owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read "Business—Environmental Matters" for more information.

We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.

        The U.S. Department of Transportation, also known as DOT, through its Pipeline and Hazardous Materials Safety Administration, also known as PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in "high consequence areas," which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

Our pipelines have become subject to increased penalties and may become subject to more stringent safety regulation.

        Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and extend the integrity management requirements to certain gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

33

---

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

        In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that our sources, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. Depending on the particular program, we may be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

        Independent of Congress, the EPA has begun to adopt federal-level regulations controlling GHG emissions under its existing Clean Air Act authority. In 2009, the EPA issued required findings under the Clean Air Act concluding that emissions of GHGs present an endangerment to human health and the environment, and issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in September 2012. We are required to report our GHG emissions for certain of our assets. On May 12, 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. However, several of the EPA's greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA may develop new rules.

        Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

34

---

The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

        In July 2010 Congress enacted the Dodd-Frank Act. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through regulation, primarily through rules to be adopted by the CFTC. The Dodd-Frank Act provisions are intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that may impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements.

        We currently receive a fuel retainage fee from certain of our customers that is paid in-kind to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to hedge our exposure to fluctuations in the price of natural gas with respect to those volumes. The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

        Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

        We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiated rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

35

---

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

        Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

        Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley, which we refer to as Section 404.

        Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

        Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the fiscal year ending December 31, 2013. In addition, pursuant to the recently enacted JOBS Act, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until the later of the year following our first annual report required to be filed with the SEC or the date we are no longer an "emerging growth company," which may be up to five full fiscal years following this offering.

36

---

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

        The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Risks Inherent in an Investment in Us

Summit Investments owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Summit Investments and our general partner have conflicts of interest with us and limited fiduciary duties, and Summit Investments and our general partner may favor their interests to the detriment of us and our other unitholders.

        Following this offering, Summit Investments will control our general partner, and appoint all of the officers and directors of our general partner, some of whom will also be officers, directors or principals of Energy Capital Partners and GE Energy Financial Services, the entities that own and control Summit Investments. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Summit Investments. Conflicts of interest will arise between Summit Investments, its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Summit Investments and its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

•

Neither our partnership agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift the focus of its investment and growth to areas not served by our assets.



•

Summit Investments is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.



•

Our general partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest.



•

Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.



•

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.



•

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.



•

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This

37

---

determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.

•

Our general partner determines which costs incurred by it are reimbursable by us.



•

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.



•

Our partnership agreement permits us to classify up to $             million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.



•

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.



•

Our general partner intends to limit its liability regarding our contractual and other obligations.



•

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.



•

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.



•

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.



•

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Please read "Conflicts of Interest and Fiduciary Duties."

Our sponsors are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

        Energy Capital Partners and GE Energy Financial Services have significantly greater resources than us and have experience making investments in midstream energy businesses. Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own interests in entities that compete with us. Energy Capital Partners and GE Energy Financial Services are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, GE Energy Financial Services owns an interest in another publicly traded midstream master limited partnership. In addition, in the future, Energy Capital Partners or GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Energy Capital Partners or GE Energy Financial Services may offer us the opportunity to buy additional assets, neither of them are under any contractual obligation to do so and we are unable to predict whether or when such opportunities may arise.

38

---

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its officers and directors or any of its affiliates, including our sponsors and their respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Fiduciary Duties."

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

        Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters' option to purchase additional common units. In addition, affiliates of our general partner will own            common and             subordinated units, representing an aggregate        % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

        The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•

our quarterly distributions;



•

our quarterly or annual earnings or those of other companies in our industry;



•

the loss of a large customer;



•

announcements by us or our competitors of significant contracts or acquisitions;



•

changes in accounting standards, policies, guidance, interpretations or principles;



•

general economic conditions;



•

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;



•

future sales of our common units; and



•

other factors described in these "Risk Factors."

Our partnership agreement limits our general partner's fiduciary duties to holders of our common and subordinated units.

        Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual

39

---

capacity, as opposed to in its capacity as our general partner or otherwise, free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•

how to allocate corporate opportunities among us and its affiliates;



•

whether to exercise its limited call right;



•

how to exercise its voting rights with respect to the units it owns;



•

whether to elect to reset target distribution levels; and



•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

        By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties."

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interest of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;



•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;



•

our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and



•

our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:



•

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;



•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

40

---

•

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Fiduciary Duties."

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

        In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

        While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period

41

---

without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our general partner) after the subordination period has ended. At the closing of this offering, affiliates of our general partner will own, directly or indirectly, approximately        % of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of Our Partnership Agreement."

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

        Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Summit Investments, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, which we project to be approximately $19.5 million for the twelve months ending June 30, 2013. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner's board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        In the event of a reset of target distribution levels, our general partner will be entitled to receive the number of common units equal to that number of common units that would have entitled it to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be

42

---

more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Summit Investments. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

        The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, affiliates of our general partner will own        % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired

43

---

such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Summit Investments to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote or consent of the unitholders.

You will experience immediate and substantial dilution in net tangible book value of $            per common unit.

        The estimated initial public offering price of $            per common unit exceeds our net tangible book value of $             per unit. Based on the estimated initial public offering price of $            per common unit, you will incur immediate and substantial dilution of $            per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."

We may issue additional units without your approval, which would dilute your existing ownership interests.

        Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our existing unitholders' proportionate ownership interest in us will decrease;



•

the amount of cash available for distribution on each unit may decrease;



•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;



•

the ratio of taxable income to distributions may increase;



•

the relative voting strength of each previously outstanding unit may be diminished; and



•

the market price of the common units may decline.

Summit Investments may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

        After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, Summit Investments will hold an aggregate of                        common units and                        subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, we have agreed to provide Summit Investments with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

44

---

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, Summit Investments will own approximately        % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Summit Investments will own approximately        % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

•

we were conducting business in a state but had not complied with that particular state's partnership statute; or



•

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

        For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

        Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

45

---

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

        We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management."

We will incur increased costs as a result of being a publicly traded partnership.

        We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

        We have included $2.5 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Tax Risks

        In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

46

---

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

        Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

        Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships; any such legislation, if enacted, may or may not be applied retroactively. We are unable to predict whether any such legislation will ultimately be enacted, and any such changes could negatively impact the value of an investment in our common units.

Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

        Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

47

---

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

        If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

        Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit

48

---

adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election."

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations and, although the U.S. Treasury Department issued proposed regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation

49

---

methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and would result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination."

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Texas and Colorado. Colorado currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

50

---

USE OF PROCEEDS

        We expect to receive net proceeds of approximately $             million, after deducting underwriting discounts, commissions and a structuring fee, but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. Our estimates assume an initial public offering price of $            per common unit. We will use the net proceeds from this offering to:

•

repay in full the remaining $             million outstanding under the promissory notes payable to our sponsors that we will assume from Summit Investments in connection with the closing of this offering;



•

repay $             million outstanding under our revolving credit facility;



•

make a cash distribution to Summit Investments of $             million in order to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us; and



•

pay estimated offering expenses of $             million.

        As of May 11, 2012, the balance under the promissory notes was $48.7 million. The promissory notes bear interest at 8%. The obligations under the promissory notes were incurred in connection with our acquisition of the Grand River system in October 2011.

        As of May 11, 2012, we had $307.0 million of indebtedness outstanding under our revolving credit facility, with a weighted average interest rate of 2.75%. The revolving credit facility matures on May 26, 2016, and borrowings bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. Borrowings made under our revolving credit facility within the last twelve months were used primarily to make distributions to our sponsors and fund capital expenditures.

        If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments the number of common units issued upon such exercise.

        The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. An affiliate of the underwriter is a lender under our revolving credit facility and will, in that respect, receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our revolving credit facility. Please read "Underwriting."

        An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, commissions and a structuring fee, to increase or decrease, respectively, by $             million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $            per common unit, would increase net proceeds to us from this offering by approximately $             million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $            per common unit, would decrease the net proceeds to us from this offering by approximately $             million. To the extent there is an increase or decrease in the net proceeds we receive from this offering, we will make a corresponding increase or decrease in the cash distribution to Summit Investments.

51

---

CAPITALIZATION

        The following table shows:

•

Summit Midstream Predecessor's historical cash and cash equivalents and capitalization, as of December 31, 2011; and



•

our as adjusted cash and cash equivalents and capitalization, as of December 31, 2011, giving effect to:



•

our receipt and use of net proceeds of $             million from the issuance and sale of                         common units to the public at an assumed initial offering price of $            per unit in the manner described in "Use of Proceeds"; and



•

the other transactions described in "Summary—Formation Transactions and Partnership Structure."

        We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations." This table assumes that the underwriters' option to purchase additional common units is not exercised.

52

---

DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of December 31, 2011, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters' option to purchase additional common units is not exercised, our net tangible book value was $             million, or $            per unit. Net tangible book value excludes $             million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

        The following table sets forth the number of units that we will issue and the total consideration to be contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:

53

---

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading "—Assumptions and Considerations" below. In addition, please read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical financial statements, and the notes thereto, included elsewhere in this prospectus.

General

        Our Cash Distribution Policy.    Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement. To that end, our partnership agreement requires us to distribute all of our available cash quarterly. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

        Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.    There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to the extent we have available cash as defined in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

•

Our cash distribution policy may be subject to restrictions on distributions under our revolving credit facility or other debt agreements entered into in the future. Our revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility."



•

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.



•

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Summit Investments) after the subordination period has ended. At the closing of this offering, Summit Investments will own our general partner as well as approximately        % of our outstanding common units and all of our subordinated units, representing an aggregate         % limited partner interest in us.

54

---

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.



•

Under Section 17-607 of the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.



•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash."



•

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate in order to service or repay our debt or fund expansion capital expenditures.

        All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $             million cash basket, that represent non-operating sources of cash. Consequently, it is possible that distributions from operating surplus may represent a return of capital. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.

        Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital.    Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions, expansion capital expenditures or otherwise, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no restrictions in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional bank borrowings (under our amended and restated revolving credit facility or otherwise) or other debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

        Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $            per unit per complete quarter, or $            per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter

55

---

ending                     , 2012. This equates to an aggregate cash distribution of approximately $             million per quarter, or approximately $             million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding immediately after the completion of this offering. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to this policy will be subject to the factors described above under the caption "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

        If and to the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds before expenses but after deducting underwriting discounts, commissions and structuring fees. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

        The table below sets forth the number of common and subordinated units to be outstanding upon the closing of this offering and the number of unit equivalents represented by the 2.0% general partner interest and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $            per unit per quarter ($            per unit on an annualized basis).

        The subordination period generally will end if we have earned and paid at least $            on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after                        , 2015. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $            (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest and the related distribution on the incentive distribution rights for any four consecutive quarter period ending on or after                        , 2013. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common

56

---

units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through September 30, 2012 based on the actual length of the period.

        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $            per unit for the twelve months ending June 30, 2013. In those sections, we present two tables, consisting of:

•

"Partnership Unaudited Historical As Adjusted Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution on a historical as adjusted basis for the year ended December 31, 2011, derived from our historical consolidated financial statements that are included in this prospectus, as adjusted to give effect to the incremental general and administrative expenses associated with being a publicly traded partnership and our estimate of the amount of our historical maintenance capital expenditures; and



•

"Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013," in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2013.

Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011

        We acquired the Grand River system from Encana in October 2011 and, therefore, our historical consolidated financial statements that are included in this prospectus do not reflect a full year of financial results of the Grand River system. If we had completed our initial public offering and the related transactions contemplated by this prospectus on January 1, 2011, our historical as adjusted cash available for distribution for the year ended December 31, 2011, which includes two months of operations attributable to the Grand River system, would have been approximately $43.0 million. This amount would have been sufficient to pay a distribution of $            per common unit on an annualized basis for the year ended December 31, 2011 and we would not have been able to pay any distributions on our subordinated units for that period.

        Unaudited historical as adjusted cash available for distribution for the year ended December 31, 2011 includes incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. These expenses are not reflected in the

57

---

historical consolidated financial statements of our Predecessor. Our estimate of incremental general and administrative expenses is based upon currently available information.

        The adjusted amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of January 1, 2011. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on January 1, 2011.

        The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2011, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related transactions contemplated by this prospectus had been consummated on January 1, 2011. Each of the adjustments presented below is explained in the footnotes to such adjustments.

58

---

Partnership Unaudited Historical As Adjusted Cash Available for Distribution

59

---

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013

        We forecast that our estimated cash available for distribution for the twelve months ending June 30, 2013 will be approximately $80.2 million. This amount would exceed by $             million the amount needed to pay the total annualized minimum quarterly distribution of $            on all of our units for the twelve months ending June 30, 2013.

        We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements in support of our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013. This forecast is a forward-looking statement and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions on which we base our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

        The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any

60

---

other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The reports of our independent registered public accounting firm included in this prospectus relate to our and our Predecessor's historical financial information, and those reports do not extend to the prospective financial information and should not be read to do so.

        When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013.

        We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements included elsewhere in this prospectus in support of our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders and the corresponding distributions on our general partner's 2.0% interest for the twelve months ending June 30, 2013. Please read below under "—Assumptions and Considerations" for further information as to the assumptions we have made for the financial forecast.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

61

---

Estimated Cash Available for Distribution

62

---

Assumptions and Considerations

        Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all unitholders for the twelve months ending June 30, 2013.

General Considerations

        As discussed further below, a significant portion of the increase in cash available for distribution for the twelve months ending June 30, 2013 as compared to the year ended December 31, 2011 is attributable to additional revenues that we expect to generate under gas gathering agreements related to our Grand River system. Because we acquired the Grand River system in October 2011, revenues from these gas gathering agreements are not included in our historical results prior to November 2011.

Revenue

        We estimate that we will generate revenue of $159.2 million for the twelve months ending June 30, 2013, compared to $103.6 million for the year ended December 31, 2011. Our forecast assumes that we recognize revenue of $13.9 million during the forecast period as a result of projected volumes being less than the minimum volume commitments for certain of our customers. The significant increase in revenue between the year ended December 31, 2011 and the twelve months ending June 30, 2013 is primarily attributable to the inclusion of our Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011. Approximately 51% of our projected revenue is expected to be generated from our Grand River system and approximately 49% is expected to be generated from our DFW Midstream system for the twelve month period ending June 30, 2013. Approximately 87% of our revenue is associated with fee-based gathering services that we provide to our customers. Approximately 8% of our revenue is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collect on our Grand River system. We generate the remainder of our revenue by charging certain customers with respect to costs we incur on their behalf to deliver pipeline quality natural gas to third-party pipelines and costs we incur to operate electric-drive compression on the Grand River system.

•

Volumes.  We estimate that we will gather an average of 885 MMcf/d for the twelve months ending June 30, 2013. This compares to our average daily throughput in March 2012 of approximately 890 MMcf/d and an average of 428 MMcf/d for the year ended December 31, 2011. This expected increase in volumes in the forecast period as compared to the year ended December 31, 2011 is primarily due to our acquisition of the Grand River system in October 2011 and is partially offset by natural declines in production from existing wells on both of our gathering systems.



•

Grand River volumes. Our average daily throughput on the Grand River system in March 2012 was approximately 575 MMcf/d. We expect throughput will be approximately

63

---

563 MMcf/d for the twelve months ending June 30, 2013, primarily based on (i) production schedules provided by certain of our customers and (ii) our assumption that our other customers will drill and connect new wells to offset the natural decline of existing wells connected to the Grand River system, thereby keeping throughput in the forecast period relatively flat with current throughput. Projected throughput for the twelve months ending June 30, 2013 compares to aggregate minimum volume commitments of 469 MMcf/d from our Grand River customers over the same time period.

•

DFW Midstream volumes. Our average daily throughput on the DFW Midstream system in March 2012 was approximately 315 MMcf/d. We expect throughput on the DFW Midstream system will be approximately 322 MMcf/d for the twelve months ending June 30, 2013, primarily based on our assumption that in the aggregate, our customers' production will be sufficient to offset the natural decline of existing wells connected to the DFW Midstream system, thereby keeping throughput in the forecast period relatively flat with current throughput. Projected throughput for the twelve months ending June 30, 2013 compares to aggregate minimum volume commitments of 183 Mmcf/d from our DFW Midstream customers over the same time period.



•

Fees.  We estimate that we will receive an average gathering fee of $0.43 per Mcf for the twelve months ending June 30, 2013, compared to $0.53 per Mcf for the year ended December 31, 2011. Our calculation of the average gathering fee is based on an analysis of the projected volumes and fixed contractual fees (subject to contractual escalation in certain cases) under each of our gas gathering agreements. We expect our average gathering fee to be lower in the forecast period as compared to the year ended December 31, 2011 primarily as a result of the inclusion of our Grand River system, which generates a lower average gathering fee per Mcf than our DFW Midstream system, in the forecast period. All of our gathering fees are fixed and subject to the terms of the gas gathering agreements we have with each of our customers.



•

Natural Gas and Condensate Sales.  Approximately 8% of our projected revenue in the twelve months ending June 30, 2013 is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense and (ii) the sale of condensate volumes that we collect on our Grand River system. We assume that we will sell the retained natural gas at Henry Hub pricing as of May 9, 2012, less a basis differential consistent with historical differentials, less contracted transportation costs. We assume that we will sell the condensate at the NYMEX crude oil strip price as of May 9, 2012 less a basis differential consistent with historical differentials. Fuel retainage volumes are projected according to specific terms embedded within all of the gas gathering agreements for our DFW Midstream customers. Condensate is projected according to historical condensate yields based primarily on projected volume from our Mamm Creek and South Parachute fields.



•

Sensitivity Analysis.  The actual volume of natural gas that we gather on our systems will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2013 is above or below our forecast. If the actual volume of natural gas we gather on our systems is below our forecast, we may not have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the forecast period. If the actual volume of natural gas we gather on our systems for the twelve months ending June 30, 2013 was 10% lower than our forecast, we would have sufficient cash available to pay the full distribution to holders of our common units and only        % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units.

64

---

Operating and Maintenance Expenses

        Our primary operating and maintenance expenses include labor costs, compression costs, ad valorem and property taxes, utilities and contract services. We estimate that we will incur operating and maintenance expenses of $48.7 million for the twelve months ending June 30, 2013, compared to operating and maintenance expenses of $29.9 million for the year ended December 31, 2011. Included in these amounts is compression expense that we incur to operate our electric-drive compression assets on our DFW Midstream system, which varies with (i) our power consumption, which is correlated to the actual throughput on our DFW Midstream system, and (ii) the cost of power. Under our gas gathering agreements with our DFW Midstream customers, we physically retain a certain percentage of each customer's throughput that we then sell to offset the power costs we incur. Under our gas gathering agreements with our Grand River customers, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets. Excluding our total compression costs, we estimate that we will incur operating and maintenance expenses of $35.9 million, or $0.11 per Mcf, for the twelve months ending June 30, 2013, compared to operating and maintenance expenses of $16.5 million, or $0.11 per Mcf, for the year ended December 31, 2011. Increased aggregate operating and maintenance expenses for the twelve months ending June 30, 2013 are primarily related to the acquisition of the Grand River system in October 2011 and the additional DFW Midstream operations personnel that were hired during the year ended December 31, 2011.

        We expect that operating and maintenance expenses will increase in the aggregate, primarily as a result of higher compression expenses, as throughput increases across our gathering systems. However, we expect operating and maintenance expenses net of compression costs on a dollar per Mcf basis to decline as throughput on our systems increases at a higher rate than our non-compression operating and maintenance expenses and our compression costs are passed on to our customers or offset by our sale of physical natural gas that we retain from our DFW Midstream customers, as applicable.

General and Administrative Expenses

        Our general and administrative expenses will primarily consist of general and administrative expenses that we incur and payments that we make to our general partner in exchange for the provision of general and administrative services, including approximately $2.5 million of expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation.

        We expect our general and administrative expenses to total approximately $20.8 million for the twelve months ending June 30, 2013, compared to general and administrative expenses of $17.5 million for the year ended December 31, 2011. The primary drivers of our anticipated increase in general and administrative expenses are our acquisition of the Grand River system in October 2011 and $2.5 million of incremental expenses related to being a publicly traded partnership, partially offset by an approximately $1.6 million reduction in non-cash compensation expenses.

Depreciation and Amortization Expense

        We estimate that depreciation and amortization expense for the twelve months ending June 30, 2013 will be $32.6 million, compared to $11.9 million for the year ended December 31, 2011. Estimated depreciation and amortization expense reflects management's estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and

65

---

amortization expense is primarily attributable to the inclusion of a full year of depreciation on our Grand River assets and expected capital investments on both the DFW Midstream system and the Grand River system.

Capital Expenditures

        We estimate that total capital expenditures for the twelve months ending June 30, 2013 will be $50.4 million, compared to $667.7 million for the year ended December 31, 2011. Approximately $590.0 million of our capital expenditures for the year ended December 31, 2011 were related to the acquisition of the Grand River system in October 2011. Capital expenditures attributable to the DFW Midstream system and Grand River system in November and December 2011 accounted for the remainder. Substantially all of our projected capital expenditures are associated with expanding our existing Grand River and DFW Midstream systems. We estimate that total capital expenditures on our Grand River system will be approximately $29.2 million for the twelve months ending June 30, 2013, which will account for approximately 58% of our total capital expenditures during the forecast period, with the DFW Midstream system accounting for the remainder.

•

Maintenance Capital Expenditures.  Historically, we did not make a distinction between maintenance and expansion capital expenditures. We estimate that we will spend $4.8 million for maintenance capital expenditures for the twelve months ending June 30, 2013. The types of maintenance capital expenditures that we expect to incur include expenditures to connect additional pad sites to maintain current volumes and expenditures to replace system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives. It has been customary in the regions in which we operate for producers to bear the cost of connecting individual wells to our pad site meters or central receipt points. In areas where multiple wells are located on a single pad site, such as on the DFW Midstream system, individual wells are connected to our measurement meter on the pad site, which is in turn connected to our gathering pipeline system. In other areas without multiple well pad sites, such as parts of the Grand River system, individual wells are connected to our nearest central receipt point meter, which in turn is connected to our pipeline gathering system.



•

Expansion Capital Expenditures.  We estimate that our expansion capital expenditures for the twelve months ending June 30, 2013 will total $45.6 million, of which approximately $26.5 million are attributable to the Grand River system and approximately $19.1 million are attributable to the DFW Midstream system. Although we expect that these expenditures will increase throughput over time, we have not assumed any additional volumes during the forecast period related to these expenditures.



•

Grand River system. The majority of our projected expansion capital expenditures on the Grand River system are associated with looping certain sections of pipeline in order to increase system capacity, optimize throughput hydraulics and operating pressures and increase our pad site connections for ongoing low-pressure Mesaverde formation drilling activities.



•

DFW Midstream system. The substantial majority of the expansion capital expenditures associated with the DFW Midstream system will be to construct new low-pressure pipeline laterals to connect additional identified pad sites for our existing customers, install additional compression assets and complete the construction of several looping pipelines on the DFW Midstream system to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures.

66

---

Financing

•

Cash and Liquidity.  At the closing of this offering, we expect to have $             million of capacity under our amended and restated revolving credit facility after using a portion of the net proceeds of this offering to repay approximately $             million currently outstanding under our amended and restated revolving credit facility. Please read "Use of Proceeds." At the closing of this offering, we expect to have outstanding indebtedness of approximately $             million and a total leverage ratio of approximately 2.0x, which we believe will provide us with sufficient liquidity to fund our anticipated expansion capital expenditures during the forecast period. We intend to fund our forecasted maintenance capital expenditures with operating cash flow.



•

Interest Expense.  We estimate that our interest expense excluding the effects of amortization of deferred loan costs for the twelve months ending June 30, 2013 will be approximately $7.8 million, compared to $2.5 million for the year ended December 31, 2011. Our projected interest expense is based on an assumed average outstanding debt balance of $200.7 million under our amended and restated revolving credit facility during the forecasted period, including borrowings to finance our projected expansion capital expenditures, with an assumed weighted average interest rate of        % and a commitment fee of         % that we expect to pay on the undrawn portion of the revolving credit facility. We have assumed no interest income with respect to the cash that we maintain on our balance sheet during the forecast period.

Regulatory, Industry and Economic Factors

        Our forecast for the twelve months ending June 30, 2013 is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.



•

There will not be any major adverse change in the midstream energy sector, commodity prices or in market, insurance or general economic conditions.



•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.



•

We will not make any acquisitions or other significant expansion capital expenditures (other than as described above).

67

---

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

        Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                         , 2012, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through                        , 2012 based on the actual length of the period.

Definition of Available Cash

        Available cash generally means, for any quarter, all cash on hand at the end of that quarter:

•

less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:



•

provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future credit needs);



•

comply with applicable law, any of our debt instruments or other agreements; and



•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter and the next four quarters);



•

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

        The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

68

---

Intent to Distribute the Minimum Quarterly Distribution

        We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $            per unit, or $            on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for a discussion of the restrictions included in our amended and restated revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

        Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $            per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any limited partner units that it owns. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.

Operating Surplus and Capital Surplus

General

        All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

        We define operating surplus as:

•

$             million (as described below); plus



•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below); plus



•

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus



•

cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date that we enter into a binding obligation

69

---

to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of; plus

•

cash distributions paid on equity issued to pay the construction-period interest on debt incurred, or to pay construction-period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less



•

all of our operating expenditures (as defined below) after the closing of this offering; less



•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less



•

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less



•

any cash loss realized on disposition of an investment capital expenditure.

        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $             million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of ordinary course asset retirements or replacements, (iv) the termination of commodity hedge contracts or interest rate hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of the contract), (v) capital contributions received and (vi) corporate reorganizations or restructurings.

        We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses to our general partner, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), director and officer compensation, repayment of working capital borrowings and non-pro rata repurchases of our units; provided, however, that operating expenditures will not include:

•

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

70

---

•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;



•

expansion capital expenditures;



•

investment capital expenditures;



•

payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;



•

distributions to our partners; or



•

non-pro rata purchases of any class of our units made with the proceeds of an interim capital transaction.

Capital Surplus

        Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

•

borrowings other than working capital borrowings;



•

sales of our equity and debt securities; and



•

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

        Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

        Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our operating income or operating capacity over the long term. We expect that a primary component of maintenance capital expenditures will include expenditures to connect additional wells to our gathering systems to offset natural declines in production over time and for routine equipment and pipeline maintenance or replacement due to obsolescence. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of.

        Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Expansion capital expenditures include interest payments (and related fees) on debt incurred and

71

---

distributions on equity issued to finance the construction of such capital improvement and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or operating income.

        Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand, for more than the short term, our operating capacity or operating income.

        Capital expenditures that are made in part for maintenance capital purposes, expansion capital purposes and/or investment capital purposes will be allocated as maintenance capital expenditures, expansion capital expenditures or investment capital expenditures by our general partner (with the concurrence of the Conflicts Committee).

Subordination Period

General

        Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $            per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

        Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after                        , 2015, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common and subordinated units equaled or exceeded $            (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;



•

the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or

72

---

exceeded (i) the sum of $            (the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during those periods on a fully diluted weighted average basis and (ii) the corresponding distribution on our 2.0% general partner interest; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

        Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after                        , 2013, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $            (150.0% of the annualized minimum quarterly distribution), plus the corresponding distribution on our general partner's 2.0% interest and related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;



•

the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $            (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted weighted average basis and (ii) the distributions made on our 2.0% general partner interest and the incentive distribution rights; and



•

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration of the Subordination Period

        When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately and automatically convert into one common unit;



•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Definition of Adjusted Operating Surplus

        Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

•

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption "—Operating Surplus and Capital Surplus—Operating Surplus" above); less



•

any net increase in working capital borrowings with respect to that period; less

73

---

•

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus



•

any net decrease in working capital borrowings with respect to that period; plus



•

any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the third bullet point above; plus



•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

        Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if

74

---

we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

        Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

        The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

        If for any quarter:

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and



•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "first target distribution");



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "second target distribution");



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "third target distribution"); and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any

75

---

additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

        In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner's interest in us immediately prior to the reset election.

76

---

        The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

        Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

        The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $            .

77

---

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be                                    common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $             for the two quarters prior to the reset.

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be                        common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $            . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $            , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $            .

        Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

78

---

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

        We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and



•

thereafter, as if they were from operating surplus.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

        Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;



•

the number of common units into which a subordinated unit is convertible;



•

target distribution levels;



•

the unrecovered initial unit price; and



•

the number of general partner units comprising the general partner interest.

79

---

        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

        If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

        The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

80

---

•

fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;



•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;



•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

        The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

•

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;



•

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and



•

thereafter, 100.0% to our general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

81

---

Adjustments to Capital Accounts

        Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

82

---

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

        The following table presents as of the dates and for the periods indicated the selected historical consolidated financial and operating data of our Predecessor. On September 3, 2009, we acquired a controlling interest in DFW Midstream Services LLC, which we refer to as our Initial Predecessor for the period prior to such date. We use the term Summit Midstream Predecessor to describe our Predecessor's operations after September 3, 2009. We acquired the Grand River system on October 27, 2011 and we have included its financial results in the financial statements of Summit Midstream Predecessor since the date of acquisition.

        The selected historical financial data for the period from January 1, 2009 to September 3, 2009 are derived from the audited historical financial statements of our Initial Predecessor included elsewhere in this prospectus. The selected historical balance sheet data as of December 31, 2009 are derived from the audited historical financial statements of Summit Midstream Predecessor that are not included in this prospectus. The selected historical consolidated financial data presented as of December 31, 2010 and December 31, 2011 and for the period from September 3, 2009 to December 31, 2009 and for the years ended December 31, 2010 and December 31, 2011 have been derived from the audited historical consolidated financial statements of Summit Midstream Predecessor included elsewhere in this prospectus. We acquired our initial assets from Energy Future Holdings Corp. effective as of September 3, 2009.

        For a detailed discussion of the information presented in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with the historical audited consolidated financial statements and related notes of our Predecessor's audited consolidated financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information below.

        The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in our business as a measure of performance and liquidity. We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation and selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit and selected gains that are unusual or non-recurring. For a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measure" on page 85.

83

---

84

---

Non-GAAP Financial Measure

        We include in this prospectus the non-GAAP financial measure Adjusted EBITDA. We provide a reconciliation of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

Adjusted EBITDA

        We define Adjusted EBITDA as net income (loss):

•

Plus:



•

Interest expense;



•

Income tax expense;



•

Depreciation and amortization expense;



•

Certain non-cash charges such as non-cash equity compensation; and



•

Selected charges / transaction costs that are unusual or non-recurring.



•

Less:



•

Interest income;



•

Income tax benefit; and



•

Selected gains that are unusual or non-recurring.

        Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and lenders, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;



•

the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;



•

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

        The GAAP measures most directly comparable to Adjusted EBITDA are net cash flows provided by operating activities and net income. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to net income. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Adjusted EBITDA has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

•

certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;



•

Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;



•

Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;



•

although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

85

---

•

our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

        Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management's decision-making process.

        The following table presents a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net income for each of the periods indicated:

 

86

---

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

        You should read the following discussion of the financial condition and results of operations of Summit Midstream Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements and related notes of Summit Midstream Partners, LLC, which we refer to as Summit Midstream Predecessor, included elsewhere in this prospectus. We sometimes refer to DFW Midstream Services LLC, or our Initial Predecessor, and Summit Midstream Predecessor collectively as our Predecessor. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

Overview

        We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of March 31, 2012, our gathering systems had approximately 380 miles of pipeline and 146,300 horsepower of compression. During March 2012, our systems gathered an average of approximately 890 MMcf/d of natural gas, of which approximately 65% was processed by third parties in order to extract natural gas liquids, or NGLs.

        We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

        Substantially all of our gas gathering agreements are underpinned by minimum volume commitments and areas of mutual interest, or AMIs. Our AMIs cover approximately 250,000 acres in the aggregate, have terms that range from 10 years to 25 years, and provide that any natural gas producing wells drilled by our customers within the AMIs are connected to our gathering systems. The minimum volume commitments, which totaled 2.6 Tcf at December 31, 2011 and, through 2020, average approximately 637 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have terms that range from 7 years to 15 years and, as of December 31, 2011, had a weighted average remaining life of 12.3 years assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

Our Operations

        Our results are driven primarily by the volumes of natural gas that we gather across our systems. For the year ended December 31, 2011, approximately 80% of our revenue was associated with fee-based gathering services that we provided to our customers. Approximately 12% of our revenue was associated with (i) the sale of physical natural gas that we retained from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collected on our Grand River system. We generated the remainder of our revenue by charging certain customers with respect to costs we incur on their behalf to deliver pipeline quality natural gas to third-party pipelines and costs we incur to operate electric-drive compression on the Grand River system.

87

---

        We contract with producers to gather natural gas from pad sites and central receipt points connected to the Grand River system and our gathering system in the Barnett Shale, which we refer to as the DFW Midstream system. These receipt points are connected to our gathering pipelines through which we compress natural gas and deliver it to third-party processing plants or downstream pipelines for ultimate delivery to end users.

        We currently provide substantially all of our gathering services under long-term, fee-based gas gathering agreements, which limit our direct commodity price exposure, and we do not take title to the natural gas we gather on behalf of our customers. Under these agreements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather. We are party to six, long-term gas gathering agreements with producers in the Barnett Shale and, in connection with our acquisition of the Grand River system from a subsidiary of Encana in October 2011, we entered into three, long-term gas gathering agreements with Encana and assumed six gas gathering agreements with five other producers, three of which are long-term agreements.

        These agreements provide us with a revenue stream that is not subject to direct commodity price risk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. On the Grand River system, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

        We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling or temporarily shut-in production due to persistently low commodity prices, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers. Please read below and "Risk Factors—Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and adversely affecting our revenues and cash available to make distributions to you over the long-term" for additional information regarding the recent decline in natural gas prices and the impact it has had on our customers and our operations.

        We have exposure to both liquids-rich and "dry" gas regions, and we believe our gathering systems are well positioned to capture additional volumes from increased producer activity in the future. Dry gas regions contain natural gas reserves that are primarily comprised of methane, as compared to liquids-rich regions that contain NGLs in addition to methane.

        In the Piceance Basin, our Grand River system benefits from its exposure to liquids-rich gas production from the Mesaverde formation. The attractive economics associated with the production from this formation, combined with our minimum volume commitments from major producers in the area, provide us with stable cash flows and visible growth in the future. In addition, certain of our customers have joint venture agreements in place that provide for the development of portions of the Piceance Basin in our AMIs utilizing third-party funds. We believe the drilling activity from these partnerships will benefit our Grand River system. The Grand River system also serves the emerging Mancos and Niobrara formations, which we expect will become more active to the extent that natural gas prices increase.

        Our DFW Midstream system benefits from its AMIs that cover the most prolific dry gas area of the Barnett Shale. We believe that this area offers our customers a compelling opportunity to maximize drilling economics due to the high estimated ultimate recovery of natural gas per well and relatively low drilling costs when compared to other dry gas resource basins. While recent market prices for natural gas have resulted in reduced drilling activity in the Barnett Shale, there remains a significant number of wells in various stages of completion in our AMIs that have already been connected to pad sites on the DFW Midstream system. These wells represent an opportunity to increase throughput on the DFW Midstream system at minimal incremental capital costs. In addition, because of the urban

88

---

environment in which the DFW Midstream system is located, we expect that this area will continue to be developed by our customers using a high density pad site drilling strategy that is designed to support multiple wells from a single location. Instead of constructing pipelines to multiple wells, we connect to an individual pad site, some of which can accommodate up to 30 wells, and gather all of the natural gas produced at that site, thus minimizing our future capital expenditures. This pad site strategy substantially increases the efficiency of both the producers' drilling activities as well as our gathering activities and economics.

How We Evaluate Our Operations

        Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include (i) throughput volume, (ii) operations and maintenance expenses, (iii) Adjusted EBITDA and (iv) distributable cash flow. We manage our business and analyze our results of operations as a single business segment.

Throughput Volume

        The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River and DFW Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

        We must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas is impacted by:

•

successful drilling activity within our AMIs;



•

the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;



•

the number of new pad sites in our AMIs awaiting lateral connections;



•

our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and



•

our ability to gather natural gas that has been released from commitments with our competitors.

        We actively monitor producer activity in the areas served by our gathering systems to pursue new supply opportunities.

Operations and Maintenance Expenses

        We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Other than utilities expense, these

89

---

expenses are relatively stable and largely independent of volumes delivered through our gathering systems, but may fluctuate depending on the activities performed during a specific period. Our compressors in the Barnett Shale are electric driven and power costs are directly correlated to the run-time of compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our Barnett Shale customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain Barnett Shale customers to deliver pipeline quality natural gas to third-party pipelines. In the Piceance Basin, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

Adjusted EBITDA and Distributable Cash Flow

        We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation and selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit and selected gains that are unusual or non-recurring. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure." Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures, to analyze our performance and liquidity. Distributable cash flow will not reflect changes in working capital balances.

        Adjusted EBITDA and distributable cash flow are used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

(Adjusted EBITDA)

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;



•

the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders;



•

our operating performance compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

(Distributable Cash Flow)

•

the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Note Regarding Non-GAAP Financial Measures

        Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Net income and net cash flows provided by operating activities are the GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be

90

---

considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

General Trends and Outlook

        Our business has been, and we expect our future business to continue to be, affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural gas supply and demand dynamics

        Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $2.13 per MMBtu as of March 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage, warm winter weather and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration ("EIA"), average annual natural gas production in the United States increased 14.1% from 55.3 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Over the same time period, natural gas consumption increased only 4.7% to 66.8 Bcf/d. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 1.6 Tcf as of March 31, 2011 to approximately 2.5 Tcf as of March 31, 2012 due to the unseasonably warm winter of 2011-2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 635 as of March 31, 2012 according to Smith Bits (a unit of Schlumberger), as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

        Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in December 2008, 50% of the electricity in the United States was generated by coal-fired power plants and in December 2011, 41% of the electricity in the United States was generated by coal-fired power plants. In January 2012, the EIA projected total annual domestic consumption of natural gas to increase from approximately 22.9 Tcf in 2009 to approximately 26.5 Tcf in 2035. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2035 to 27.8 Tcf. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long-term throughout the United States.

91

---

Growth in production from U.S. shale plays

        Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources. While the EIA expects total domestic natural gas production to grow from 20.6 Tcf in 2009 to 27.8 Tcf in 2035, it expects shale gas production to grow to 13.6 Tcf in 2035, or 49% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics as compared to most conventional plays.

        In recent years, well-capitalized producers have leased large acreage positions in the Piceance Basin, the Barnett Shale and other unconventional resource plays. To help fund their drilling program in many of these areas, including in the Piceance Basin and the Barnett Shale, a number of producers have also entered into joint venture arrangements with large international operators and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin, the Barnett Shale and other unconventional resource plays, which we believe will result in sustained drilling activity.

        As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high BTU content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.

Interest rate environment

        The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Rising operating costs and inflation

        The current high level of natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

92

---

Results of Operations—Combined Overview

        The following table and discussion presents certain historical consolidated financial data of our Predecessor for the periods indicated.

93

---

Items Affecting the Comparability of Our Financial Results

        The historical results of operations of our Predecessor may not be comparable to our future results of operations for the reasons described below:

•

Because we acquired our initial interest in the DFW Midstream system from Texas Competitive Electric Holdings Company, LLC ("TCEH"), an indirect subsidiary of Energy Future Holdings Corp., effective as of September 3, 2009, the financial and operational data for 2009 that is presented and discussed in this prospectus is generally bifurcated between the period that our Initial Predecessor owned those assets and the period from the acquisition of those assets by Summit Midstream Predecessor through December 31, 2009.



•

The historical consolidated financial statements and related notes of our Initial Predecessor:



•

have been carved out of the accounting records maintained by Energy Future Holdings and its subsidiaries. Certain accounts such as trade accounts receivables, accounts payable, pre-paid expenses and certain accrued liabilities relating to the activities of our Initial Predecessor were recorded on the books of other Energy Future Holdings entities and estimates of those accounts have been included in the consolidated financial statements;



•

include an estimate for general and administrative ("G&A") expenses, as Energy Future Holdings did not allocate any of the central finance and administrative costs to this operating entity;



•

reflect the operation of the DFW Midstream system with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate it. Please read "Business—Business Strategies;" and



•

do not include any results from certain natural gas gathering assets that we acquired from Chesapeake Energy Corporation on September 3, 2009 that are included in the DFW Midstream system.



•

The historical consolidated financial statements and related notes of Summit Midstream Predecessor:



•

reflect a 75% ownership interest in the entity we acquired from TCEH from September 4, 2009 to June 18, 2010, the date on which Summit Midstream Predecessor purchased the remaining 25% membership interest from TCEH for $90.7 million;



•

include transaction expenses of $3.9 million in 2009 that we incurred in connection with our formation and our initial acquisition of assets. These expenses include an aggregate of $2.2 million paid to Energy Capital Partners and $1.7 million paid to third parties for strategic, advisory, management, legal, and consulting services;

94

---

•

include charges associated with a transition services agreement that we entered into with Energy Future Holdings effective September 3, 2009. Under the terms of the transition services agreement, we paid Energy Future Holdings $38,700, $0.1 million and $0.1 million for the years ended December 31, 2011 and 2010 and the period from September 3, 2009 through December 31, 2009, respectively; and



•

do not include any results from the acquisition of the Grand River system prior to November 2011.



•

We anticipate incurring approximately $2.5 million of G&A expense attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. These incremental G&A expenses are not reflected in the historical consolidated financial statements of our Initial Predecessor or Summit Midstream Predecessor.



•

Following the closing of this offering, we intend to make cash distributions to our unitholders equal to our minimum quarterly distribution of $             per unit per quarter ($             per unit on an annualized basis). Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our amended and restated revolving credit facility and future issuances of equity and debt securities. Historically, Summit Midstream Predecessor largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy its capital expenditure requirements.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        Volume.    Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 293.7 MMcf/d, or 219%, from 134.3 MMcf/d for the year ended December 31, 2010 to 428.0 MMcf/d for the year ended December 31, 2011. This increase was due to the continued development of the DFW Midstream system. There were 275 wells and 58 drilling pad sites and 160 wells and 33 drilling pad sites connected to the DFW Midstream system as of December 31, 2011 and 2010, respectively. The DFW Midstream system included 104 and 83 miles of pipeline as of December 31, 2011 and December 31, 2010, respectively. Throughput volumes for the DFW Midstream system averaged 329.0 MMcf/d for the year ended December 31, 2011. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 605.9 MMcf/d for the two months that are included in our financial results for the year ended December 31, 2011.

        Revenue.    Total revenue increased $71.9 million, or 227%, from $31.7 million for the year ended December 31, 2010 to $103.6 million for the year ended December 31, 2011. Gas gathering revenue increased $62.1 million, or 211%, from $29.4 million for the year ended December 31, 2010 to $91.4 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system, offset by a decrease of $0.04 per Mcf, or 7%, in the average throughput rates from $0.57 per Mcf for the year ended December 31, 2010 to $0.53 per Mcf for the year ended December 31, 2011. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $11.0 million for the two months that are included in our financial results for the year ended December 31, 2011. Natural gas and condensate sales

95

---

increased $9.9 million, or 391%, from $2.5 million for the year ended December 31, 2010 to $12.4 million for the year ended December 31, 2011. The increase in revenue attributable to natural gas and condensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the Grand River system was $0.6 million for the two months ended December 31, 2011.

        Operations and maintenance expense.    Operations and maintenance expense increased $20.4 million, or 214%, from $9.5 million for the year ended December 31, 2010 to $29.9 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors increased $9.1 million, or 206%, from $4.4 million for the year ended December 31, 2010 to $13.5 million for the year ended December 31, 2011 due to increased volumes and the associated increased power cost to operate the compression. Operations and maintenance expenses for the Grand River system were $3.9 million for the two months that are included in our financial results for the year ended December 31, 2011.

        General and administrative ("G&A") expenses.    G&A expenses increased $7.4 million, or 74%, from $10.0 million for the year ended December 31, 2010 to $17.5 million for the year ended December 31, 2011. We recorded non-cash compensation expense of $3.4 million for the year ended December 31, 2011 relative to profits interests held by certain members of management. We did not record non-cash compensation expense for the year ended December 31, 2010. Salary and benefit expenses increased $2.0 million, or 45%, from $4.3 million for the year ended December 31, 2010 to $6.3 million for the year ended December 31, 2011 due to increased headcount to support our growth. We did not have these expenses for the year ended December 31, 2010. Due diligence costs relative to potential asset acquisitions were $1.3 million in 2011 compared to insignificant due diligence costs in 2010. The increase in G&A expenses was offset by decreases in legal expenses for the year ended December 31, 2011 compared to the year ended December 31, 2010. Legal expenses decreased $2.0 million in 2011 primarily as the result of decreased legal activities relative to relationships with contractors and sub-contractors associated with the DFW Midstream system. We had $1.8 million in settlement expenses in 2010 related to a dispute with a contractor at the DFW Midstream system.

        Transaction costs.    Transaction costs were $3.2 million for the year ended December 31, 2011. These transaction costs were primarily related to the acquisition of the Grand River system. We did not have transaction costs for the year ended December 31, 2010.

        Depreciation and amortization expense.    Depreciation and amortization expense increased $8.1 million, or 208%, from $3.9 million for the year ended December 31, 2010 to $12.0 million for the year ended December 31, 2011. This increase was primarily the result of the depreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system in 2011. Depreciation and amortization expense for the Grand River system was $3.8 million for the two months that are included in our financial results for the ended December 31, 2011.

        Interest expense and affiliated interest expense.    Interest expense increased $3.1 million for the year ended December 31, 2011. This increase was primarily the result of entering into our revolving credit facility in May 2011 and related amortization of deferred loan costs of $0.6 million and issuing $200 million of promissory notes to our sponsors in connection with the acquisition of the Grand River system. We did not have a revolving credit facility or promissory notes in 2010 and, therefore, we had no interest expense for the year ended December 31, 2010.

96

---

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

        Volume.    Throughput volumes increased 118.6 MMcf/d, or 755%, from 15.7 MMcf/d for the 2009 Initial Predecessor Period to 134.3 MMcf/d for the year ended December 31, 2010. Throughput volumes increased 118.9 MMcf/d, or 772%, from 15.4 MMcf/d for the 2009 Summit Midstream Predecessor Period to 134.3 MMcf/d for the year ended December 31, 2010. Throughput volumes increased significantly for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period due to the continued development of the DFW Midstream system. There were 160 wells and 33 drilling pad sites and 20 wells and 4 drilling pad sites connected to the DFW Midstream system as of December 31, 2010 and December 31, 2009, respectively. The DFW Midstream system included 83 miles and 12 miles of pipeline as of December 31, 2010 and December 31, 2009, respectively.

        Revenue.    Revenue increased $28.0 million, or 770%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $31.7 million for the year ended December 31, 2010. Gas gathering revenue increased $25.8 million, or 710%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $29.4 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Average throughput rates decreased $0.01 per Mcf, or 2%, from $0.58 per Mcf for the 2009 Summit Midstream Predecessor Period to $0.57 per Mcf for the year ended December 31, 2010. Natural gas and condensate sales were $2.5 million for the year ended December 31, 2010. Revenue for the year ended December 31, 2010 included sales of natural gas that we retain from DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale.

        Operations and maintenance expense.    Operations and maintenance expense increased $7.3 million, or 341%, from $1.0 million for the 2009 Initial Predecessor Period and $1.1 million for the 2009 Summit Midstream Predecessor Period to $9.5 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors were $4.4 million for the year ended December 31, 2010. Utility expense for the 2009 Initial Predecessor Period and for the 2009 Summit Midstream Predecessor Period was insignificant. The remaining increase in operations and maintenance expense for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period was primarily the result of additional throughput on the DFW Midstream system and additional compression being placed into service.

        General and administrative expenses.    G&A expenses increased $6.5 million, or 184%, from $0.6 million for the 2009 Initial Predecessor Period and $2.9 million for the 2009 Summit Midstream Predecessor Period to $10.0 million for the year ended December 31, 2010. Legal expenses increased $2.0 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period primarily as the result of legal activities relative to relationships with contractors and sub-contractors associated with the DFW Midstream system. The remaining increase in G&A expenses for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period is the result of our ownership of the DFW Midstream system for the full year 2010. We acquired our initial assets of our DFW Midstream system effective as of September 3, 2009. Additionally, we increased our headcount in 2010 compared to 2009 as we continued construction and development of the DFW Midstream system.

        Transaction costs.    Transaction costs were $3.9 million for the 2009 Summit Midstream Predecessor Period. These transaction costs were primarily related to the acquisition of the DFW Midstream system in September 2009. We did not have transaction costs for the 2009 Initial Predecessor Period or the year ended December 31, 2010.

97

---

        Depreciation and amortization expense.    Depreciation and amortization expense increased $2.6 million, or 216%, from $0.9 million for the 2009 Initial Predecessor Period and $0.3 million for the 2009 Summit Midstream Predecessor Period to $3.9 million for the year ended December 31, 2010. This increase was primarily the result of the depreciation associated with assets placed into service in connection with the expansion and development of the DFW Midstream system in 2010.

        Interest expense.    Interest expense decreased $0.2 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. Interest expense for the 2009 Initial Predecessor Period included $0.2 million related to an intercompany capital allocation charge during the ownership of the DFW Midstream system by our Initial Predecessor. We did not have an intercompany capital allocation charge for the year ended December 31, 2010.

Liquidity and Capital Resources

        Since the acquisition of our initial assets in September 2009, our sources of liquidity have included cash generated from operations, equity investments by our sponsors, Energy Capital Partners and GE Energy Financial Services, and borrowings under our revolving credit facility.

        Following the closing of this offering we expect our sources of liquidity to include:

•

cash generated from operations;



•

borrowings under our amended and restated revolving credit facility; and



•

issuances of debt and equity securities.

        We believe that the cash generated from these sources will be sufficient to allow us to distribute the minimum quarterly distribution to all of our unitholders and the corresponding distribution on our 2.0% general partner interest and to meet our requirements for working capital and capital expenditures for the foreseeable future.

Cash Flows

        The following table reflects cash flows for the applicable periods:

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        Operating activities.    Cash flows from operating activities increased by $30.4 million, or 318%, from $9.6 million for the year ended December 31, 2010 to $40.0 million for the year ended December 31, 2011. The increase in cash flows from operating activities is a direct result of the significant increase in volumes on the DFW Midstream system during 2011 compared to 2010 and the inclusion of two months of operations on the Grand River system for the year ended December 31, 2011.

        Investing activities.    Cash flows used for investing activities increased by $514.0 million, or 334%, from $153.7 million for the year ended December 31, 2010 to $667.7 million for the year ended December 31, 2011. The increase in cash flows used for investing activities is primarily due to the acquisition of the Grand River system for $590.0 million. Capital expenditures decreased by $79.2 million, or 49%, from $154.0 million for the year ended December 31, 2010 to $74.8 million for the year ended December 31, 2011. Capital expenditures in 2010 were higher due to the installation and commissioning of compressor stations on the DFW Midstream system.

98

---

        Financing activities.    Cash flows from financing activities increased by $519.7 million, or 455%, from $114.1 million for the year ended December 31, 2010 to $633.8 million for the year ended December 31, 2011. The increase in cash flows from financing activities is primarily due to the acquisition of the Grand River system. Summit Midstream Predecessor received equity contributions of $410 million and a $200.0 million non-recourse loan from Energy Capital Partners and GE Energy Financial Services to acquire the Grand River system. Summit Midstream Predecessor closed on our revolving credit facility in May 2011. Upon closing the revolving credit facility, Summit Midstream Predecessor made a distribution to our sponsors of $132.9 million of the $142.0 million drawn at closing.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

        Operating activities.    Cash flows from operating activities increased by $15.2 million from $0.6 million for the 2009 Initial Predecessor Period and $(6.2) million for the 2009 Summit Midstream Predecessor Period to $9.6 million for the year ended December 31, 2010. The increase in cash flows from operating activities is related to the increased volumes on the DFW Midstream system during 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. The increase in volumes resulted in an increase of net income by $15.6 million, from $(0.8) million for the 2009 Initial Predecessor Period and $(6.6) million for the 2009 Summit Midstream Predecessor Period to $8.2 million for the year ended December 31, 2010.

        Investing activities.    Cash flows used for investing activities increased by $48.5 million, or 46%, from $40.8 million for the 2009 Initial Predecessor Period and $64.4 million for the 2009 Summit Midstream Predecessor Period to $153.7 million for the year ended December 31, 2010. The cash used for investing activities increased due to the installation and commissioning of the compressor stations on the DFW Midstream system during 2010.

        Financing activities.    The cash flows from financing activities during the 2009 Initial Predecessor Period, the 2009 Summit Midstream Predecessor Period and the year ended December 31, 2010 were capital contributions from Energy Capital Partners. During the 2009 Summit Midstream Predecessor Period, Energy Capital Partners contributed $107.0 million at formation and then contributed an additional $27.9 million to support capital needs related to the construction of the DFW Midstream system. In the year ended December 31, 2010, Energy Capital Partners contributed $194.1 million in support of the continued growth and construction of the DFW Midstream system. In June 2010, we purchased the remainder of Energy Future Holdings' membership interests related to the DFW Midstream system for $90.7 million, which was funded with the capital contributed by Energy Capital Partners.

Off-Balance Sheet Arrangements

        We do not have any off-balance sheet arrangements.

Capital Requirements

        The natural gas gathering segment of the midstream energy business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

•

maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

99

---

•

expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term.

        For the year ended December 31, 2011, our total capital expenditures were $667.7 million. Approximately $590.0 million of the capital expenditures in 2011 were related to our acquisition of the Grand River system in October 2011. The remainder were primarily associated with the construction of new pipeline infrastructure to connect new pad sites on our DFW Midstream system and to connect new pad sites and central receipt points on Grand River system. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We have estimated, however, that approximately $3.1 million of these capital expenditures were maintenance capital expenditures.

        We are forecasting $67.2 million in capital expenditures for the year ending December 31, 2012, of which $61.6 million represents expansion capital expenditures and $5.6 million represents maintenance capital expenditures. Our 2012 forecasted expansion capital expenditures include:

•

$15.7 million to construct pipeline laterals and tie in additional pad sites for customers on the DFW Midstream system;



•

$11.6 million related to the installation of additional compression assets and construction of several looping pipelines on the DFW Midstream system in order to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures;



•

$10.4 million to expand and improve hydraulic efficiency of the Mamm Creek field in the Grand River system;



•

$9.9 million related to the construction of medium-pressure pipelines and the installation of additional compression-related assets in the Orchard field on the Grand River system; and



•

$10.0 million associated with the procurement and installation of pad site meter equipment at approximately 400 existing pad sites on the Grand River system.

        As of March 31, 2012, we have spent approximately $14.5 million of our 2012 expansion capital budget.

        We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities.

Distributions

        We intend to pay a quarterly distribution at an initial rate of $            per unit, which equates to an aggregate distribution of $             million per quarter, or $             million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering and the related distributions on our 2.0% general partner interest. We do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our Amended and Restated Revolving Credit Facility

        Effective May 7, 2012, we amended and restated our revolving credit facility with a syndicate of lenders to increase our borrowing capacity from $285 million to $550 million. Substantially all of our assets are pledged as collateral under our amended and restated revolving credit facility. The amended and restated revolving credit facility matures in May 2016 and, at our option, borrowings thereunder bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. The

100

---

events that constitute an event of default under our amended and restated revolving credit facility are customary for credit facilities of this size and nature.

        Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:

•

permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to be less than 2.50 to 1.00;



•

permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to be above either 5.00 to 1.00 (or 5.50 to 1.00 if we have made certain business acquisitions);



•

incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject to customary exceptions for permitted liens;



•

make any investments, subject to customary exceptions for certain permitted investments;



•

engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactions of such types;



•

pay dividends or make cash distributions, provided that we may make quarterly distributions, subject to customary exceptions with respect thereto (including the right to pay dividends or make distributions) so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants under the amended and restated credit agreement;



•

enter into swap agreements and power purchase power agreements, subject to customary exceptions, such as the allowance of swap agreements and power purchase agreements in the ordinary course of business; and



•

enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.

        As of May 11, 2012, we were in compliance with the financial and other covenants in our amended and restated revolving credit facility.

        In addition to the uses described in "Use of Proceeds," we expect borrowings under our amended and restated revolving credit facility to be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) capital expenditures. There was approximately $307.0 million drawn under our amended and restated revolving credit facility at May 11, 2012.

Promissory Notes Payable to Sponsors

        In connection with our acquisition of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million, have an 8% interest rate and mature on October 27, 2013. Summit Investments has the option to elect to pay the interest in kind and it made this election for all interest due as of December 31, 2011. The amount of interest paid in kind and accrued to the balance of the notes as December 31, 2011 is $2.9 million, resulting in $202.9 million as the amount outstanding on the notes as of December 31, 2011. During 2011, Summit Investments capitalized $0.9 million of the $2.9 million interest expense related to costs incurred on capital projects under construction. As of December 31, 2011, the aggregate carrying value of these notes approximated the fair value.

101

---

        The promissory notes payable to our sponsors will be repaid in full using a portion of the expected net proceeds from this offering. As of May 11, 2012, the balance under the promissory notes was $48.7 million.

Credit Risk and Customer Concentration

        We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. A significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. Chesapeake, Carrizo Oil & Gas, Inc., TOTAL and Energy Transfer Fuels each accounted for more than 10% of our $103.6 million in consolidated revenue for the year ended December 31, 2011, accounting for 34%, 17%, 10% and 12%, respectively, of our consolidated revenue for that year. Although we have contractual arrangements with each of these counterparties of varying duration, if one or more of these customers were to default on their contractual obligations or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.

Contractual Obligations

        The table below summarizes our contractual obligations and other commitments as of December 31, 2011:

Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

        We have exposure to changes in interest rates on our indebtedness associated with our amended and restated revolving credit facility. The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate

102

---

credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

        Summit Midstream Predecessor entered into our revolving credit facility in May 2011, which was amended and restated on May 7, 2012. A hypothetical increase or decrease in interest rates of 1.0% would have increased or decreased, respectively, our interest expense by $1.5 million for the year ended December 31, 2011.

Commodity Price Risk

        Because we currently generate a substantial majority of our revenues pursuant to long-term, fixed-fee gas gathering agreements that include minimum volume commitments and AMIs, our only direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system and (iii) the sale of condensate volumes that we collect on the Grand River system. Our gas gathering agreements with our Barnett Shale customers permit us to retain a certain quantity of natural gas that is intended to offset the power costs we incur to operate our electric-drive compression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices at the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas sales. We do not enter into risk management contracts for speculative purposes.

Impact of Seasonality

        Our results of operations on our gathering systems are not materially affected by seasonality.

Critical Accounting Policies and Estimates

        In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities as of the balance sheet date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses, including fair value measurements and disclosure of contingencies, during the reporting period. Our actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the accounting policies currently underlying our most significant financial statement items:

Contingencies

        The financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.

Depreciation

        Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property, plant and equipment and revise our estimates. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning

103

---

useful lives of similar assets. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.

Property, Plant and Equipment

        Property, plant, and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirement of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in the statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

Impairment of Long-Lived Assets

        Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposal of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows.

Compensatory Awards

        Certain of our current and former employees received Class B membership interests, which are net profits interests, in DFW Midstream Management, LLC or Summit Midstream Management, LLC. The Class B units participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Class B members. The Class B units are accounted for as compensatory awards. The grants vest ratably over four to five years. We determined the fair value of the Class B units as of the respective grant dates. The Class B units were valued utilizing an option pricing method, which models the Class A and Class B units as call options on the underlying equity value considering the rights and preferences of each class of equity to allocate a fair value to each class. The significant inputs used in the option pricing method are the length of holding period restriction, the discount for lack of marketability and volatility.

Revenue Recognition

        We earn revenue from natural gas gathering services provided to natural gas producers and record such revenue as gathering services and other fees. We also earn revenue from the sale of physical natural gas retained from our customers to offset power expenses associated with electric-driven compression on the DFW Midstream system. We record this revenue as fuel retainage revenue. We record costs incurred which are reimbursed by our customers, on a gross basis in the consolidated statement of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured.

104

---

INDUSTRY OVERVIEW

General

        The midstream natural gas industry is the link between the exploration and production of natural gas from the wellhead or lease and the delivery of the natural gas and its other components to end-use markets. Companies within this industry create value at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and natural gas liquids, or NGLs, and then routing the separated dry gas and NGL streams for delivery to end-markets or to the next intermediate stage of the value chain.

        The following diagram illustrates the groups of assets commonly found along the natural gas value chain:

Midstream Services

        The range of services utilized by midstream natural gas service providers are generally divided into the following categories:

Gathering

        At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression

        Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression,

105

---

volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration

        Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing

        The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation

        The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.

Transportation and Storage

        Once the raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.

Contractual Arrangements

        Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical types of contracts are described below.

106

---

Fee-Based

        Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure.

Percent-of-Proceeds

        Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.

Keep-Whole

        Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processor compensates the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

        There are two forms of contracts utilized in the transportation and storage of natural gas:

Firm

        Firm service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a "demand" or "capacity reservation" fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas gathered. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.

Interruptible

        Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Market Fundamentals

Natural Gas Demand

        Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 25% of all energy used in the United States in 2010, representing 24 Tcf of natural gas. The EIA estimates that over the next 25 years, total domestic energy consumption will increase by over 10%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and

107

---

natural gas vehicles. The following charts show the allocation of natural gas usage by end user as well as the relative position of natural gas as a power generation fuel source as of 2010.

Source: EIA, Annual Energy Outlook 2012 Early Release (January 2012).

        According to the EIA, as shown in the chart below, during the period from 2001 through 2010, natural gas consumption increased by 9.6% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 66.8 Bcf/d in 2011. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation and commercial/residential sectors, where consumption grew by approximately 42.3% and 1.3%, respectively. The growth in these sectors was partially offset by an approximate 7.6% decline in natural gas consumption in the less seasonal industrial sector.

U.S. Annual & Average Daily Natural Gas Consumption

Source: EIA, U.S. Natural Gas Consumption by End Use (April 2012).

        Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater

108

---

demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 24.3 Tcf in 2010 to 26.5 Tcf in 2035.

Natural Gas Supply

        Domestic natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 32.4% in 2010. According to EIA data, during the three-year period from January 2007 through December 2010 domestic production of natural gas increased by an average of approximately 3.8% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

        In 2011, the EIA estimated that the United States held 827 Tcf of technically recoverable shale gas resource. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 49% in 2035 as compared with 23% in 2010.

109

---

Natural Gas Production by Source, 1990-2035

Source: EIA, Annual Energy Outlook 2012 Early Release (January 2012).

110

---

BUSINESS

Overview

        We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of March 31, 2012, our gathering systems had approximately 380 miles of pipeline and 146,300 horsepower of compression. During March 2012, our systems gathered an average of approximately 890 MMcf/d of natural gas, of which approximately 65% was processed by third parties in order to extract NGLs. We believe that we are positioned to grow through the increased utilization and further development of our existing assets. In addition, we intend to grow our business through strategic partnerships with large producers to provide midstream services for their upstream development projects, as well as through acquisitions in our existing areas of operation and in new areas.

        We generate a substantial majority of our revenue under long-term fee-based, natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

        Substantially all of our gas gathering agreements are underpinned by minimum volume commitments and areas of mutual interest, or AMIs. Our AMIs cover approximately 250,000 acres in the aggregate, have terms that range from 10 years to 25 years, and provide that any natural gas producing wells drilled by our customers within the AMIs are connected to our gathering systems. The minimum volume commitments, which totaled 2.6 Tcf at December 31, 2011 and, through 2020, average approximately 637 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have terms that range from 7 years to 15 years and, as of December 31, 2011, had a weighted average remaining life of 12.3 years assuming minimum throughput volume for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

        We were formed in 2009 by members of our management team and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. We are currently owned by Energy Capital Partners, GE Energy Financial Services, a global investor in essential, long-lived and capital intensive energy assets with over $20 billion in energy investments worldwide, and certain members of our management team.

        For the year ended December 31, 2011, we generated $103.6 million of revenue, $37.4 million of net income and $60.0 million of Adjusted EBITDA. These amounts reflect only two months of operations from our Grand River system, which we acquired in October 2011. Please read "—Our Assets—Grand River System." For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

        Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are summarized below.

111

---

Grand River System

        In October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin of western Colorado, which we refer to as the Grand River system, from Encana for $590 million. The Grand River system comprises approximately 270 miles of low-pressure pipeline and 97,500 horsepower of compression and is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado. All of the natural gas gathered on the Grand River system is discharged to Enterprise Products Partners L.P.'s pipeline serving its 1.7 Bcf/d processing facility located in Meeker, Colorado. For the month ended March 31, 2012, the Grand River system gathered an average of approximately 575 MMcf/d from six producers, including Encana as the anchor customer.

        The Grand River system primarily gathers natural gas produced by our customers from the liquids-rich Mesaverde formation within the Piceance Basin. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling activities for several decades. The Grand River system also gathers natural gas produced from our customers' wells targeting the deeper Mancos and Niobrara Shale formations, which have higher initial production rates and lower Btu gas content than Mesaverde wells. Over the last two years, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara Shale formations. Based on our customers' current drilling expectations, we anticipate the majority of our near-term throughput on the Grand River system will continue to be comprised of Mesaverde formation production.

        We intend to expand the Grand River system by connecting additional pad sites within our AMIs, adding new customers and acquiring nearby gathering systems. We expect that, to the extent natural gas prices increase from current levels, our customers will accelerate drilling activities targeting the Mancos and Niobrara shale formations, which will provide us with an opportunity to construct a new medium pressure pipeline system to gather the resulting production and increase throughput on the Grand River system.

DFW Midstream System

        In September 2009, we acquired approximately 17 miles of pipeline and 2,500 horsepower of electric-drive compression in north-central Texas, which we refer to as the DFW Midstream system, from Energy Future Holdings and Chesapeake. Since the initial acquisition, we have expanded the DFW Midstream system by adding approximately 93 miles of pipeline to connect 62 of 68 currently identified pad sites and installing an incremental 46,300 horsepower of electric-drive compression. The DFW Midstream system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers, directly or indirectly, with downstream pipelines serving the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana. For the month ended March 31, 2012, the DFW Midstream system gathered an average of approximately 315 MMcf/d from six producers.

        Our DFW Midstream system benefits from its location within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale formation. This area is commonly referred to as the core of the Barnett Shale and contains the most prolific wells drilled to date. Construction of the DFW Midstream system is substantially complete and enables our customers to efficiently produce natural gas by utilizing horizontal drilling techniques throughout the vast majority of our AMIs from pad sites already connected to the DFW Midstream system. Given the urban nature of our area of operations, in what we consider to be the "core of the core" of the Barnett Shale, we expect that the majority of future natural gas drilling in this area will occur from these existing connected pad sites, which should enable us to increase throughput and cash flows with minimal additional capital expenditures.

112

---

Business Strategies

        Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:

•

Increasing capacity of and throughput volumes on our existing systems.  We intend to continue to focus on maximizing the utilization of our assets by increasing volume throughput from existing customers and connecting new customers to our systems. The DFW Midstream system is designed to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the DFW Midstream system and do not require significant additional capital expenditures. In addition, we seek to optimize our existing systems by adding third-party volumes that in general would not otherwise be pursued by large upstream producers who are primarily focused on gathering their own production volumes.



•

Capitalizing on organic growth opportunities.  Our existing gathering systems provide us with significant organic expansion opportunities. We intend to leverage our management team's expertise in constructing, developing and optimizing midstream infrastructure assets to grow our business through organic development projects that are designed to extend our geographic reach, diversify our customer base, increase the number of our natural gas receipt points and maximize volume throughput. Our expansion of the DFW Midstream system is expected to increase the system to approximately 120 miles of 8 inch to 30 inch pipeline and 54,800 horsepower of electric-drive compression. This expansion includes installing additional electric-drive compression that we expect will increase throughput capacity on the DFW Midstream system from 410 MMcf/d to over 450 MMcf/d. We expect that this incremental throughput capacity will be utilized by our existing customers who we expect to drill on previously connected pad sites and new pad sites that we will connect to our system. We expect pad site connections to increase from 62 as of April 2012 to 68 as of June 2013. Additional projects that we expect to undertake during 2012 include:



•

Continuing the construction of a new medium-pressure gathering system alongside portions of our existing low-pressure system in the Piceance Basin. In connection with our acquisition of the Grand River system, we entered into a contractual arrangement with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.



•

Pursuing new customers currently operating in close proximity to our existing gathering infrastructure in the Barnett Shale and the Piceance Basin in order to maximize system capacity utilization. We have successfully pursued this strategy since acquiring the DFW Midstream system in 2009 and it is highlighted by our addition of EOG and Vantage Energy as new customers in 2009 and 2010, respectively. We will continue to pursue this strategy in the Barnett Shale and the Piceance Basin and are currently in discussions with multiple producers to expand our asset footprint and increase our natural gas receipt points.



•

Maintaining our focus on fee-based revenue with minimal direct commodity price exposure.  As we expand our business, we intend to maintain our focus on providing midstream energy services under fee-based arrangements. Our midstream services are almost exclusively provided under long-term, fee-based contracts with terms ranging from 10 years to 25 years. We do not take title to the natural gas that we gather for our customers and, as a result, our business is not directly exposed to commodity price fluctuations. In addition, we have secured AMIs from certain of our customers covering all of their natural gas production from approximately 150,000 acres in the Piceance Basin and 100,000 acres in the Barnett Shale. We believe that our focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows and increasing our quarterly distributions over time.

113

---

•

Partnering with large natural gas producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We pursue opportunities to partner with established producers in unconventional resource basins to develop new infrastructure that we believe will complement our existing midstream assets or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of a strategic acreage position in an unconventional resource play and represent assets that are well-positioned for accelerated production growth but have minimal existing midstream energy infrastructure to support such growth. We have been successful with this strategy and will continue to pursue similar opportunities that utilize our management team's experience in constructing, developing and operating large scale midstream infrastructure. We seek to promote commercial relationships with established producers, such as Encana on the Grand River system and Chesapeake on the DFW Midstream system, who are willing to serve as an anchor customer and are willing to commit to long-term volume and AMIs.



•

Diversifying our asset base by exploring acquisition and development opportunities in various geographical areas and other sectors of the midstream industry. While our natural gas gathering operations in the Piceance Basin and the Barnett Shale currently represent our core business, we intend to diversify our business into other sectors of the midstream industry such as crude oil gathering, storage and transportation, through both greenfield development projects and acquisitions, and into other geographic regions. We and our sponsors are frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energy infrastructure assets. Working together with our sponsors, we intend to continue to evaluate opportunities to acquire or develop other midstream energy infrastructure assets that complement our existing business and allow us to leverage our asset base and our management team's development and industry expertise.

Competitive Strengths

        We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:

•

Strategically located assets in core areas of prolific unconventional basins supported by existing partnerships with large producers to provide midstream services for their development projects.  Our midstream energy infrastructure assets are strategically positioned within the core areas of two established unconventional resource plays. The formations in the basins served by our assets have relatively low drilling and completion costs. We believe that producers will continue their drilling and completion activities in the core areas of unconventional natural gas shale basins even if natural gas prices do not increase significantly from current levels because the return economics associated with core-area wells remain favorable in lower pricing environments compared to more marginal areas of production. We believe that continued drilling activity in these basins positions us to pursue attractive growth opportunities by further developing and optimizing our systems and by developing or acquiring complementary systems within our geographic areas of operation.



•

Grand River system. The Grand River system is located in the Piceance Basin and currently serves the established liquids-rich Mesaverde formation and is optimally located for expansion to serve the emerging Mancos and Niobrara Shale formations. In the Piceance Basin, production from the emerging Mancos and Niobrara Shale formations has only recently begun, as producers have started drilling wells in these formations in the last two years. We are constructing a new medium-pressure gathering system to service anticipated higher pressure gas production from the emerging Mancos and Niobrara Shale formations.



•

DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, Texas, currently the largest natural gas producing county in the state. We

114

---

consider this area to be the "core of the core" of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. We believe that the AMIs underpinning our system are substantially undeveloped compared to other areas in the Barnett Shale due to the lack of historical gathering infrastructure in this area and limited associated drilling activity. We believe that our AMIs and our system footprint provide us with a competitive advantage to add additional producers and incremental volumes in this growing area of the Barnett Shale at a competitive capital cost.

•

Fee-based revenues underpinned by long-term contracts.  A substantial majority of our revenue for the year ended December 31, 2011 was generated under long-term, fee-based gas gathering agreements. Several of our customers are among the largest producers in each of our areas of operation. In the Piceance Basin, we have a 25-year AMI covering approximately 111,000 acres and a 15-year minimum volume commitment with Encana for approximately 1.5 Tcf. Together with our other gas gathering agreements with producers in the Piceance Basin, we have AMIs covering approximately 150,000 acres, average minimum volume commitments of 496 MMcf/d through 2020 and total volume commitments of almost 2.1 Tcf in the Piceance Basin through 2026. Our gas gathering agreements with our Barnett Shale customers have AMIs covering approximately 100,000 acres in the high-growth core area of the Barnett Shale and minimum volume commitments of approximately 492 Bcf through 2020. We believe that having long-term, fee based gas gathering agreements with minimal direct commodity price exposure enhances the predictability of our performance.



•

Capital structure and financial flexibility.  At the closing of this offering, we expect to have approximately $     million of borrowing capacity available to us under our amended and restated revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital will provide us with the requisite financial flexibility to execute our growth and expansion strategy.



•

Experienced management team with proven record of asset acquisition, construction, development, operation and integration expertise. Our executive management team has an average of 16 years of energy experience and a proven track record of identifying and consummating significant acquisitions in addition to partnering with major producers to construct and develop midstream infrastructure. As demonstrated by our current business, our management team has demonstrated particular expertise in constructing new—and developing and optimizing underutilized—midstream assets, which are key elements of our growth strategy. We employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream energy projects.



•

Relationships with large and committed financial sponsors.  Our sponsors, Energy Capital Partners and GE Energy Financial Services, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality midstream energy assets. Energy Capital Partners has indicated that it intends to use us as its primary platform for the acquisition, construction and development of future midstream infrastructure assets; however, it is not obligated to do so. We believe our relationship with both of our sponsors will be a competitive advantage, as they both bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will benefit us as we seek to grow our business. In addition, we believe that Energy Capital Partners and GE Energy Financial Services, as the indirect owners of our general partner interest, all of our incentive distribution rights and a        % limited partner interest in us, will be motivated to promote and support the successful execution of our business strategies.

115

---

Our Sponsors

        We were formed in 2009 by members of our management and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us. To date, Energy Capital Partners has formed 21 investment platforms across its funds with investments in the power generation, electric transmission, midstream natural gas and renewable sectors of the energy industry. In August 2011, Energy Capital Partners sold an interest in Summit Investments to GE Energy Financial Services. GE Energy Financial Services invests globally in essential, long-lived and capital-intensive energy assets. To date, GE Energy Financial Services has invested over $20 billion in energy investments worldwide, of which approximately $2.4 billion has been committed to midstream-related portfolio companies.

Our Assets

        Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are discussed in more detail below.

Grand River System

        The following table provides information regarding our Grand River system as of March 31, 2012.

[Piceance Basin asset map]

        In October 2011, we acquired the Grand River system from Encana for $590 million. The Grand River system is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado, and comprises approximately 270 miles of 3 inch to 24 inch diameter pipeline and approximately 97,500 horsepower of compression. The Grand River system gathers natural gas from the Mesaverde, Mancos and Niobrara Shale formations located within the Piceance Basin. All of the natural gas volumes gathered on the Grand River system are discharged to third-party pipelines that deliver to Enterprise Products Partners L.P.'s 1.7 Bcf/d processing facility located in Meeker, Colorado.

        The Grand River system has total throughput capacity of 770 MMcf/d and for the month ended March 31, 2012 gathered an average of approximately 575 MMcf/d. The system gathers production from the Mamm Creek, South Parachute and Orchard fields in the area around Rifle, Colorado. The Grand River system is underpinned by long-term, fee-based gas gathering agreements with Encana, WPX Energy, Bill Barrett Corporation and Antero Resources that include annual minimum volume commitments with terms ranging from 10 to 15 years and AMIs with terms ranging from 10 years to 25 years. As of December 31, 2011, these gas gathering agreements had remaining minimum volume commitments totaling approximately 2.1 Tcf over the next 15 years, an average of approximately 496 MMcf/d through 2020, and AMIs covering approximately 150,000 acres for terms of up to 25 years.

116

---

Our customers do not have leases that currently cover our entire AMIs in the Piceance Basin but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the Grand River system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

        The Grand River system is currently a low-pressure gathering system that was originally designed to gather natural gas produced from traditional vertical wells focused on the shallower, higher-BTU Mesaverde formation. Our largest Grand River customer, Encana, currently has more than 1,700 wells on approximately 400 pad sites connected to our existing low-pressure gathering system. We also receive natural gas from other producer customers at nine central receipt points on the Grand River system. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize the existing available throughput capacity.

        In connection with our acquisition of the Grand River system, we entered into a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

DFW Midstream System

        The following table provides information regarding our DFW Midstream system as of March 31, 2012.

[DFW Midstream asset map]

        The DFW Midstream system is located within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale geologic formation. We consider this area to be the core of the Barnett, which contains the most prolific wells, including the two largest wells drilled to date, in the Barnett Shale. The DFW Midstream system, which has been under construction since 2008, includes gathering lines ranging from 8 inches to 30 inches in diameter and is located along existing electric transmission corridors and under both private and municipal property. The system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers with downstream pipelines serving the established Waha, Carthage and Perryville natural gas market hubs in Texas and Louisiana.

        Our development of the DFW Midstream system is underpinned by six long-term, fee-based gas gathering agreements with Chesapeake, TOTAL, Carrizo, EOG, Exxon Mobil and Vantage. As of December 31, 2011, these gas gathering agreements have remaining minimum volume commitments totaling approximately 492 Bcf and average, through 2020, approximately 141 MMcf/d. In addition, these gas gathering agreements have AMIs that cover approximately 100,000 acres through 2030. Our customers do not have leases that currently cover our entire AMIs in the Barnett Shale but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the DFW Midstream system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

117

---

        We have owned and operated the DFW Midstream system since 2009, when we acquired it from Energy Future Holdings and concurrently acquired certain complimentary pipeline and other related gathering system assets from Chesapeake. We simultaneously entered into a long-term gas gathering agreement with Chesapeake as our anchor customer that included a 20-year AMI covering approximately 95,000 acres and a 10-year minimum volume commitment totaling approximately 450 Bcf. At the time of the acquisition, the DFW Midstream system had average throughput of approximately 10 MMcf/d and had approximately 17 miles of pipeline and 2,500 horsepower of installed electric-drive compression in service.

        Since the acquisition, we have expanded the DFW Midstream system by adding approximately 93 miles of additional pipeline and 46,300 horsepower of electric-drive compression. For the month ended March 31, 2012, the DFW Midstream system had average throughput of approximately 315 MMcf/d. We continue to develop the DFW Midstream system to extend our gathering reach, diversify our customer base, increase our receipt points and maximize throughput on the system. In 2012, we intend to continue to connect additional pad sites located within our AMIs and expand the throughput capacity from 410 MMcf/d to over 450 MMcf/d by installing additional electric-drive compression. The system will include approximately 120 miles of low- and high-pressure gathering lines and 54,800 horsepower of electric-drive compression. As of December 31, 2011, 276 wells on 58 pad sites were connected to the DFW Midstream system and 64 additional wells were in various stages of completion, 45 of which are on existing pad sites that we currently serve and 19 of which are on pad sites to which we intend to connect.

        While there has been substantial development of the broader 24-county Barnett Shale over the past decade, southeastern Tarrant County, which is located in the core area of the Barnett Shale, has been largely undeveloped due to the urban landscape and the absence of natural gas gathering infrastructure. The DFW Midstream system, which is primarily located in southeast Tarrant County, has addressed the historical lack of gathering infrastructure and currently provides producers in the area with a safe, efficient and reliable solution to deliver their natural gas to market. Tarrant County, which is currently the largest natural gas producing county in Texas, experienced an increase in natural gas production from 1.6 Bcf/d in October 2009 to 2.0 Bcf/d in October 2011. Over this same period, throughput on the DFW Midstream system increased from approximately 10 MMcf/d to approximately 380 MMcf/d, which accounted for approximately 90% of Tarrant County's increased natural gas production.

        We believe the production profile of wells drilled within our AMIs, which includes the two largest wells ever drilled in the Barnett Shale, will continue to attract drilling activity over the long term as producers become more selective in their drilling locations in order to maximize their returns. We also believe that the acreage dedicated to the DFW Midstream system is substantially undeveloped as evidenced by our 100,000 acre gathering footprint and our customers' desire to reduce well spacing below 50 acres to maximize recoverable reserves. We believe our strategic location in the core of the core of the Barnett Shale provides us with a competitive advantage to add incremental throughput with limited additional investment capital due to the anticipated future, high-density, infill drilling from our customers on connected pad sites and nearby pad sites that have yet to be connected. This high-density, infill drilling, is magnified in our area given the urban landscape and the desire of our producer customers to minimize their surface footprint.

Gas Gathering Agreements

        We derive revenue primarily from long-term, fee-based, gas gathering agreements, or GGAs, with some of the largest and most active producers in our areas of operation. The following describes the material provisions included in the majority of our firm gas gathering agreements with our significant customers, including our natural gas gathering agreements with Chesapeake, Encana, Carrizo Oil and Gas and WPX Energy.

118

---

AMIs and Contract Terms

        Our gas gathering agreements contain AMIs. The AMIs generally have terms that range from 10 years to 25 years and require that any production by our customers within the AMIs flow through our gathering systems. Under certain of our GGAs, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. If we choose to forego a discretionary opportunity presented by the customer, such as constructing a lateral to an additional pad site, or constructing additional pipeline infrastructure or related assets in connection with a customer's expansion of its drilling operations, the customer may, in certain circumstances, construct the additional infrastructure and sell it to us at a price equal to their cost plus an applicable margin, or, in some cases, release the relevant acreage dedication from the AMI.

Minimum Volume Commitments

        Our gas gathering agreements contain minimum volume commitments, or MVCs, pursuant to which our customers guarantee to ship a minimum volume of natural gas on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. The original terms of the MVCs range from 7 to 15 years. In addition, certain of our customers have an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.

        If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods in which the customer's actual throughput volumes exceed its MVC. This mechanism allows the customer to forego paying gathering fees in excess of its MVC for the applicable period to the extent that it has made a shortfall payment with respect to one or more preceding periods.



•

To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped excess natural gas on our DFW Midstream system relative to its MVC. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.



•

To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall payment owed in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular GGA.

119

---

Fuel Retainage Fees and Cost Pass-Throughs

        Our GGAs on our DFW Midstream system allow us to retain a small fixed percentage of the natural gas that we receive at the receipt points to offset the costs we incur to operate our electric-drive compressors. On average, we retain nominal amounts of the natural gas received at the receipt points on the DFW Midstream system. Our GGAs on our Grand River system allow us to (i) charge our customers for the electricity costs we incur to operate our electric-drive compressors and (ii) utilize physical gas on the Grand River system to operate our gas-fired compressors.

Pressure Variance Penalties

        Our GGAs require us to maintain certain specified operating pressures on our gathering systems, both on a system-wide basis and with respect to each receipt point. We are also required to maintain certain minimum operating pressures at certain of our compressor stations. If we fail to maintain our required system and receipt point operating pressures, we can be subject to penalties in the form of substantial reductions in our gathering fees (subject, in certain circumstances, to force majeure relief). These reductions generally range from 25% to 75%, depending on the duration of the pressure variance. With respect to compressor station pressure variances, we are subject to penalties in the form of loss of our fuel retainage fees and our ability to pass our electricity costs on to the customer for a period of time, depending on the duration of the pressure variance. With respect to system and receipt point pressure variances that persist for extended periods of time (generally exceeding four months in any consecutive twelve month period), our customers are entitled to additional remedies, including:

•

a 100% reduction in gathering fees applicable to future shipments until the end of the first month following the resolution of the pressure variance; and



•

the ability to release all or a portion of the customer's future gas production from the GGA.

Competition

        The natural gas gathering, compression and transportation business is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to end-use markets, location, available capacity, capital expenditures and fuel efficiencies.

        In the future, we may face competition for production drilled outside of our AMIs and on attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition.

Safety and Maintenance

        We are subject to regulation by DOT under the Natural Gas Pipeline Safety Act of 1968, as amended, also known as the NGPSA, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas pipeline facilities. In the Pipeline Safety Act of 1992, also known as the PSA, Congress expanded DOT's regulatory authority to include "regulated gathering lines" that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002, also known as the PSIA, and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, also known as the PIPES Act, established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.

120

---

        DOT has delegated the implementation of safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations, similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW gathering system is located, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

        While repairs, remediation or preventative or mitigation measures resulting from integrity management inspections could obligate us to make material expenditures, we do not anticipate such an outcome because our pipelines are relatively new.

        Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and extend the integrity management requirements to certain gathering lines. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

        We believe that we are in compliance with existing safety laws and regulations and we cannot predict the outcome of new regulatory initiatives; however, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues.

        We are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act, or the OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to the OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in

121

---

atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We are also subject to EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety, community right to know laws, and the security of our facilities.

Regulation of the Oil and Natural Gas Industries

General

        Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at uncontrolled market prices; however, regulation of gathering and transportation services may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services. FERC and FTC are also authorized to prevent and sanction market manipulation in natural gas markets and petroleum markets, respectively. State and municipal regulations may apply to the production and gathering of natural gas, the construction and operation of natural gas and crude oil facilities, and the rates and practices of gathering systems and intrastate pipelines.

Regulation of Oil and Natural Gas Exploration, Production and Sales

        Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.

        Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of resources, including provisions for the unitization or pooling of producing properties, the establishment of maximum rates of production from wells, and the regulation of spacing of wells. These state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering by us.

Regulation of the Gathering and Transportation of Natural Gas

        We believe that our gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA, although we are subject to FERC's anti-market manipulation regulations (see Anti-Market Manipulation Rules below). The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas

122

---

gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

        Our gathering of natural gas is also affected by the availability, terms and cost of downstream transportation services. The rates and terms for access to pipeline transportation services are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing systems have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. FERC's regulations require, among other things, that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of FERC's initiatives has been to eliminate the interstate pipelines' traditional role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a non-discriminatory basis. The rates for such transportation and storage services are subject to FERC ratemaking authority, and FERC exercises its authority by applying cost-of-service principles, allowing for the negotiation of rates where there is a cost-based alternative rate or granting market-based rates in certain circumstances, typically with respect to storage services.

        Natural gas production, gathering and transportation may be subject to state and local regulations that may change from time to time. Our construction of new gathering facilities and expansion of existing gathering facilities may be subject to state and local regulation, including approval and permit requirements. Regulation of our operations may cause us to incur additional operating costs or limit the quantities of gas we may gather. In addition, state ratable take statutes and regulations generally require us to take natural gas production that may be tendered to us for handling without undue discrimination. These statutes are designed to prohibit discrimination in favor of one source of supply over another source of supply and they restrict our right to decide whose production we gather.

        Gathering systems and pipelines that operate only in a single state may be subject to regulation by state regulatory authorities with respect to safety (under a federal certification) and rates and practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we have filed a tariff with the Texas Railroad Commission to establish rates and terms of service for our DFW operations. We have not been required to file a tariff in Colorado for our Grand River assets. Both of these states have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint.

        Intrastate pipelines that provide interstate transportation service are regulated by FERC under Section 311 of the NGPA as to rates and other terms and conditions of service with respect to interstate gas shipments, unless an exemption from such regulation applies (such as for gathering lines). We believe that our pipelines are gathering systems that are therefore exempt from Section 311 requirements.

        Changes in federal, state, or local law or policy may affect us either directly or indirectly. While we cannot predict what further action legislators or regulators will take, we do not believe that any such

123

---

action taken will affect us differently, in any material way, than other midstream companies with which we compete.

Regulation of Crude Oil and NGL Transportation Rates

        In a number of instances the ability to transport and sell crude oil and NGLs is dependent on pipelines whose rates and other terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992, state regulatory jurisdiction under state statutes, or both. Interstate transportation rates for crude oil and NGLs, among other liquid commodities, are regulated by FERC, and, in general, these rates must be cost-based or based on rates in effect in 1992, although FERC has established an indexing system for such transportation rates which allows pipelines to take an annual inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. FERC has also established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances.

        In other instances involving intrastate-only transportation of crude oil, NGLs and other products, the ability to transport and sell such commodities is dependent on transportation by pipelines at rates, and on other terms and conditions of service that are subject to regulation by state regulatory authorities. Such pipelines may be subject to state regulation with respect to safety (under a federal certification) and rates and other practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of intrastate liquids pipelines varies from state to state. Many states operate on a complaint-based system and state authorities have generally not initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.

Anti-Market Manipulation Rules

        We are subject to the anti-market manipulation provisions in the NGA, as amended by EPAct 2005, which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, FTC holds statutory authority under the EISA to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to one million dollars ($1,000,000) per day per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Failure to comply with such market rules, regulations and requirements could have a material adverse effect on our business, results of operations, and financial condition.

Environmental Matters

General

        Our operation of pipelines and other facilities for the gathering, compressing and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities,

124

---

we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•

requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;



•

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;



•

delaying system modification or upgrades during permit reviews;



•

requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and



•

enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

        Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

        We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

        Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and

125

---

severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

        We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

        We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Act (OPA)

        In 1991, the EPA adopted regulations under the OPA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan, or SPCC, for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

        Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply

126

---

with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

        Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. The rule may require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. Compliance with the final rule currently is required by October 2013. We are continuing our evaluation of the cost impacts of the final rule.

        On June 28, 2011, the EPA issued a final rule, effective August 29, 2011 modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule would not be required until at least 2013. We are currently evaluating the impact that this final rule will have on our operations.

        On April 17, 2012, the EPA finalized rules that establish new air emission control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or 60 days after the final rule is published in the Federal Register. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, the EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, which may impact our customers. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. These requirements may result in increased operating costs for producers who drill near our pipelines, which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations. For additional information about hydraulic

127

---

fracturing and related environmental matters, please read "Business—Environmental Matters—Hydraulic Fracturing."

        These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unit holders.

Water Discharges

        The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

Hydraulic Fracturing

        The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities, and we believe that our facilities will not be materially adversely affected by such requirements. However, a portion of our customers' natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process. Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between the latter part of 2012 and 2014. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities. On May 4, 2012, the BLM issued a proposed rule to regulate hydraulic fracturing on public

128

---

and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.

        Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. We cannot predict whether any other legislation will be enacted in the future and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Risk Factors—Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues."

Endangered Species

        The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas.

National Environmental Policy Act

        The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

        Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent by 2020 compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

129

---

        In the United States, legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a "cap and trade" program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an "air pollutant," and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act.

        In addition, in September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. We are required to report under these rules for certain of our assets. The EPA continues to consider additional climate change requirements, such as the March 2011 proposed rules regarding future coal-fired power plants. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. However, due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact that related developments will have on us.

        Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

        The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Anti-terrorism Measures

        The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

Title to Properties and Rights-of-Way

        Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on

130

---

which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to perpetual easements between us and the underlying fee owner, or permits with governmental authorities. Our Predecessor leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the exception of certain permits with governmental entities that have been applied for, but not yet issued.

Employees

        We do not have any employees. The officers of our general partner will manage our operations and activities. As of March 31, 2012, Summit Midstream Partners, LLC employed 73 people who provide direct, full-time support to our operations, including 19 field-level employees we hired from Encana in connection with our acquisition of the Grand River system. Subsequent to the closing of this offering, all of the employees required to conduct and support our operations will be employed by our general partner or its affiliates. None of these employees are covered by collective bargaining agreements, and our general partner considers its employee relations to be good.

Legal Proceedings

        Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

131

---

MANAGEMENT

Management of Summit Midstream Partners, LP

        We are managed by the directors and executive officers of our general partner, Summit Midstream GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Summit Investments owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Director Independence

        Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed limited partnership like us to have, and we do not intend to have, a majority of independent directors on the board of directors of our general partner.

Committees of the Board of Directors

        The board of directors of our general partner will have an audit committee, or the Audit Committee, and a conflicts committee, or the Conflicts Committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

        Our general partner will have an Audit Committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. Our general partner will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of the Audit Committee. Those rules permit our general partner to have an audit committee that has one independent member upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. The Audit Committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the Audit Committee.

Conflicts Committee

        At least two members of the board of directors of our general partner will serve on our Conflicts Committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The Conflicts Committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, employees of any of its affiliates, may not hold any ownership interest in our general partner or us and our subsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time, and must meet

132

---

the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Directors and Executive Officers

        Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

        Steven J. Newby has been the President and Chief Executive Officer of our general partner since May 2012. Mr. Newby was a founding member of Summit Midstream Partners, LLC and has been the President and Chief Executive Officer of Summit Midstream Partners, LLC since its formation in September 2009. Mr. Newby's background includes over 15 years of oil and gas experience with a focus on the midstream sector of the energy industry. Mr. Newby was a founding member of SunTrust Bank's Corporate Energy industry specialty group and ultimately became a Managing Director and Head of the Project Finance Group within SunTrust's Capital Markets division. In 2007, Mr. Newby joined ING Investment Management to manage a $300 million proprietary fund focused on the private and public investment in the energy infrastructure space. Mr. Newby is a graduate of the University of North Carolina at Chapel Hill with a B.S. in Business Administration with a concentration in Finance.

        Matthew S. Harrison has been the Senior Vice President and Chief Financial Officer of our general partner since May 2012. Prior to joining our general partner, Mr. Harrison was the Senior Vice President and Chief Financial Officer of Summit Midstream Partners, LLC since September 2011. Mr. Harrison's background includes over 12 years of energy and finance experience. Mr. Harrison joined Summit Midstream Partners, LLC from Hiland Partners, LP, where he served as Executive Vice President and Chief Financial Officer, Secretary and Director from February 2008 to September 2011. Prior to joining Hiland, Mr. Harrison was a Director in the Energy & Power Merger & Acquisitions group at Wachovia Capital Markets from October 2007 to February 2008 and a Director in the Mergers & Acquisitions group at A.G. Edwards & Sons, Inc. from July 1999 to October 2007. Mr. Harrison is a Certified Public Accountant and was a Senior Accountant for PricewaterhouseCoopers for five years. Mr. Harrison received an MBA from Northwestern University—Kellogg Graduate School of Management in 1999 and a B.S. in Accounting from the University of Tennessee in 1992.

        Brad N. Graves has been the Senior Vice President of Corporate Development of our general partner since May 2012. Prior to joining our general partner, Mr. Graves was the Senior Vice President of Corporate Development of Summit Midstream Partners, LLC since April 2010. He was previously a Partner with Crestwood Midstream Partners, LLC from February 2008 until March 2010. Mr. Graves

133

---

has served as Executive Vice President—Business Development of Genesis Energy, LP (AMEX: GEL) from August 2006 until November 2007. He also served as Vice President—Offshore Commercial for Enterprise Products Partners L.P. (NYSE: EPD) from 2004 until August 2006. Prior to 2004, Mr. Graves served in a variety of commercial roles at EPD and GulfTerra Energy Partners, LP (NYSE: GTM), prior to its merger with EPD. In his roles with EPD and GTM, Mr. Graves participated in numerous greenfield projects developed in the Gulf of Mexico. Mr. Graves earned a B.B.A. in Accounting from Texas A&M University in 1989 and an MBA in Marketing and Finance from the University of Saint Thomas in 1994.

        Rene L. Casadaban has been the Senior Vice President of Engineering, Construction, and Operations of our general partner since May 2012. Prior to joining our general partner, Mr. Casadaban was the Senior Vice President of Engineering, Construction and Operations of Summit Midstream Partners, LLC from November 2010 to April 2012. Mr. Casadaban has 20 years of project management experience for onshore, offshore and deepwater pipeline systems. Prior to joining Summit Midstream Partners, LLC, Mr. Casadaban worked for Enterprise Products Partners L.P. from 2006 to 2010 as the Director for Deepwater Development of floating production platforms and offshore pipelines. Mr. Casadaban has also served as an independent consultant to ExxonMobil and GulfTerra for Gulf of Mexico and international pipeline projects. At Land & Marine, Mr. Casadaban was responsible for managing domestic and international pipeline river crossings and beach approaches by horizontal directional drilling. Mr. Casadaban is a graduate of Auburn University with a B.S. in Building Construction.

        Brock M. Degeyter has been the Senior Vice President and General Counsel of our general partner since May 2012. Mr. Degeyter joined Summit Midstream Partners, LLC in January 2012 as Senior Vice President and General Counsel. Mr. Degeyter's background includes over ten years of energy, finance and business law experience. Prior to joining our general partner, Mr. Degeyter worked in the corporate legal department for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director of Corporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with the firm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed to practice law in the states of Texas and Louisiana. Mr. Degeyter received a B.A. in Political Science from Louisiana State University and a J.D. from Loyola University College of Law in New Orleans.

        Thomas K. Lane has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Lane has been a partner of Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton College and an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

        Andrew F. Makk has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Makk has been a Principal at Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, he was a co-founder of a privately held energy company from 2002 to 2005, which built a portfolio of energy projects in Europe on behalf of a private equity fund through the acquisition of existing projects and development of new projects. Prior to 2002, Mr. Makk spent nine years with Enron International in various power and LNG asset development roles and became Head of Asset Development for Enron Europe in London. He received a B.S.M. in Finance from Tulane University

134

---

and an MBA from the Fuqua School of Business at Duke University. Mr. Makk was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

        Curtis A. Morgan has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Morgan has served as the President and Chief Executive Officer of EquiPower Resources Corp. since May 2010. Prior to joining EquiPower Resources Corp., he served as an Operating Partner of Energy Capital Partners from May 2009 to May 2010. Prior to joining Energy Capital Partners, he served as President and Chief Executive Officer of FirstLight Power Enterprises from November 2006 to April 2009. Mr. Morgan has also held leadership positions at NRG Energy, Mirant Corporation and Reliant Energy. Mr. Morgan received a B.A. in Accounting from Western Illinois University and an MBA in Finance and Economics from the University of Chicago. He is a Certified Public Accountant. We believe that Mr. Morgan's extensive executive, financial and operational experience bring important and necessary skills to the board of directors.

        Tyson R. Yates has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with GE Energy Financial Services, Inc. Mr. Yates currently serves as Managing Director of the Midstream portfolio group at GE Energy Financial Services, a position he assumed in March 2007. Over the past 12 years, Mr. Yates has held a variety of positions at GE Energy Financial Services, including Senior Vice President in the Midstream sector investment group. In his current position, Mr. Yates serves on a number of boards that currently include Southern Star Central Corp., a regulated interstate natural gas pipeline system headquartered in Kentucky, SourceGas Holdings Inc., a local gas distribution company headquartered in Colorado, and Phoenix Park Gas Processors Ltd., a natural gas processing plant in Trinidad. Prior to joining GE Energy Financial Services, Mr. Yates held the position of Senior Manager in the Special Acquisition Services and Audit practice at Deloitte & Touche LLP. Mr. Yates has a B.S. in Accounting from the University of Florida and is a Certified Public Accountant. We believe that Mr. Yates's extensive executive and financial experience bring important and necessary skills to the board of directors.

Executive Compensation

        The following describes the material components of our compensation policies with respect to the following individuals, who are our general partner's executive officers and referred to as the "named executive officers":

•

Steven J. Newby, President and Chief Executive Officer;



•

Matthew S. Harrison, Senior Vice President and Chief Financial Officer; and



•

Rene L. Casadaban, Senior Vice President, Engineering, Construction and Operations.

135

---

Summary Compensation Table for 2011

        The following table sets forth certain information with respect to the compensation paid to our named executive officers for the year ended December 31, 2011.

Narrative Disclosure to Summary Compensation Table

Elements of Compensation

        The primary elements of compensation for the named executive officers are base salary, annual incentive compensation and long-term equity-based compensation awards. The named executive officers also receive certain retirement, health, welfare and additional benefits as described below.

        Base Salary.    Base salaries for our named executive officers have generally been set at levels deemed necessary to attract and retain individuals with superior talent. None of our named executive officers received any base salary adjustments or increases during 2011, other than cost of living increases provided to all of our employees. However, effective March 2012, generally in preparation for this offering, base salary increases were approved for each named executive officer other than

136

---

Mr. Harrison, whose base salary was set in September 2011 upon his commencement of employment with us. The base salaries of our named executive officers before and after the increase, as applicable, are set forth in the following table:

        Annual Incentive Compensation.    For 2011, Messrs. Newby and Harrison had target bonuses of $223,500 and $221,250, respectively, or 75% of their base salaries. Our board of directors used its discretion to award both executives bonuses slightly in excess of their targets because, although we underperformed on our Adjusted EBITDA targets, we successfully completed our acquisition of the Grand River system under their leadership. Pursuant to Mr. Harrison's employment agreement, his bonus was not prorated, despite his September hire date.

        Mr. Casadaban's target incentive compensation was 75% of his base salary, or $150,000. Quantitative factors determined 70% of Mr. Casadaban's incentive compensation and qualitative factors determined 30%. Quantitative factors considered in determining the bonus included achievement of certain Adjusted EBITDA thresholds, construction goals and operational and safety goals. Although we underperformed on our Adjusted EBITDA targets, we achieved near target on our construction goals and significantly above target on our operational goals. As a result, Mr. Casadaban was awarded $79,800 or 76% of target for the portion of his bonus based on quantitative factors, and $75,200 or 167% of target for the portion of his bonus based on qualitative factors, primarily due to his significant contributions to the closing of the acquisition of the Grand River system. In total, Mr. Casadaban was awarded approximately 103% of his target incentive compensation for 2011.

        Long-Term Equity-Based Compensation Awards.    The named executive officers were each granted equity-based compensation awards in the form of interests ("upstairs profits interests") in a collective partnership vehicle, referred to in this prospectus as Summit Management, through which our named executive officers indirectly hold Class B percentage interests in Summit Investments ("downstairs profits interests"). The downstairs profits interests represent indirect interests in Summit Investments' future profits, and allow Summit Management to share in distributions by Summit Investments only after Summit Investments' Class A Members have received distributions in an amount equal to the sum of the fair market value of the downstairs profits interests at the time of grant plus any capital contributions made subsequent to the date of grant. The upstairs profits interests entitle the named executive officers to receive from Summit Management the proceeds of any distributions received by Summit Management from Summit Investments in respect of the corresponding downstairs profits interests, subject to the terms set forth in the partnership agreement of Summit Management. The upstairs profits interests are referred to in this prospectus as the Pre-IPO Equity Awards.

        The Pre-IPO Equity Awards were granted subject to a five-year time-based vesting schedule, subject to the named executive officer's continued employment through the applicable vesting date. The Pre-IPO Equity Awards are eligible for an additional one year of vesting in the event the named executive officer's employment is involuntarily terminated by the applicable employer without cause, or is terminated due to the named executive officer's death or disability, or, in the case of Mr. Newby, is

137

---

terminated by him due to his resignation with good reason (as defined in the employment agreements, described below). The Pre-IPO Equity Awards are eligible for full 100% accelerated vesting if the named executive officer's employment is involuntarily terminated without cause or, in the case of Mr. Newby, is terminated by the named executive officer due to his resignation with good reason, within the 12 months after a change in control of Summit Investments. In the event of a named executive officer's termination of employment for any other reason, the named executive officer's Pre-IPO Equity Awards will be forfeited.

        Pursuant to the applicable partnership agreements, the vested downstairs profits interests may be repurchased by the applicable employer or Energy Capital Partners in certain circumstances. In the event of the termination of a named executive officer's employment due to death, disability, termination by the applicable employer without cause or, in the case of Mr. Newby, resignation with good reason or non-extension of the term of the employment agreement, the repurchase price will be equal to the value of the downstairs profits interests in a hypothetical liquidation of the applicable employer pursuant to the rights and preferences set forth in the partnership agreement, assuming all assets were sold for their fair market value. In the event of termination for cause, resignation (in the case of Mr. Newby, without good reason) or a purported transfer by the named executive officer or the management company in violation of the partnership agreement, the repurchase price will equal $0. In the event of a repurchase of the downstairs profits interests, the corresponding upstairs profits interests will be repurchased from the named executive officer by Summit Management for the same repurchase price.

        Going forward, we expect that equity-based incentive awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process. In anticipation of this offering, we intend to adopt a new long-term equity incentive plan, which is discussed in more detail under "2012 Long-Term Incentive Plan" below.

        Retirement, Health and Welfare and Additional Benefits.    The named executive officers are eligible to participate in such employee benefit plans and programs as we may from time to time offer to our employees, subject to the terms and eligibility requirements of those plans. The named executive officers are eligible to participate in a tax-qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2011, we made a fully vested contribution on behalf of each of the 401(k) plan's participants equal to 3% of such participant's salary for the year.

Outstanding Equity Awards at December 31, 2011

        The following table provides information regarding the Pre-IPO Equity Awards held by the named executive officers as of December 31, 2011.

138

---

Employment and Severance Arrangements

        We have entered into employment agreements with Steven J. Newby (dated September 3, 2009), and Matthew S. Harrison (dated September 15, 2011). Rene Casadaban is not a party to an employment agreement.

        The current term of Mr. Newby's employment agreement expires on August 31, 2012. Mr. Harrison's employment agreement has an initial term of two years, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 90 days prior to the expiration of the then-applicable term. Each employment agreement provided for the named executive officer's initial base salary and a performance-based bonus ranging from 0% to 150% of base salary, with a target of 75% of base salary. Mr. Harrison's employment agreement also provides for a $25,000 cash signing bonus, reimbursement for up to $60,000 in relocation expenses incurred in relocating to Atlanta, Georgia, and reimbursement for tax preparation expenses in the amount of $10,000 per year. No such reimbursements were yet paid to Mr. Harrison in 2011.

        Each employment agreement provides for a cash severance payment upon a termination by us without cause or by the named executive officer for good reason, which is defined generally as the named executive officer's termination of employment within two years after the occurrence of (i) a material diminution in the named executive officer's authority, duties or responsibilities, (ii) a material diminution in the named executive officer's base compensation, (iii) a material change in the geographic location at which the named executive officer must perform his services under the agreement or (iv) any other action or inaction that constitutes a material breach of the employment agreement by us. Each employment agreement provides that the named executive officer's severance payment will be equal to the sum of his annual base salary and the annual bonus payable in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days in the period beginning on the date of termination and ending on the later of (a) the last day of the then-applicable term of the employment agreement and (b) the first anniversary of the date of termination (the "severance period") and the denominator of which is 365. The severance payment is payable in equal installments during the severance period.

        Following any termination of employment other than one resulting from non-extension of the term, each of Messrs. Newby and Harrison will be subject to a post-termination non-competition covenant through the severance period. Following any termination of employment, each of Messrs. Newby and Harrison will be subject to a one-year post-termination non-solicitation covenant.

        In the case of Messrs. Newby and Harrison, if the named executive officer's employment is terminated due to non-extension of the term by us or by the named executive officer, we may choose to subject him to a non-competition covenant for up to one year post-termination. If we exercise this "noncompete option", then the named executive officer will be entitled to a severance payment in an amount equal to the sum of his annual base salary and annual bonus payable in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period.

        Any severance payment payable to a named executive officer pursuant to his employment agreement will be subject to his execution and non-revocation of a release of claims in favor of us.

139

---

        As described above, the Pre-IPO Equity Awards provide for certain acceleration in the event of certain terminations of employment, including certain terminations in connection with a change in control of Summit Investments.

2012 Long-Term Incentive Plan

        Prior to the consummation of this offering, our general partner intends to adopt a 2012 Long-Term Incentive Plan, or LTIP, pursuant to which our, our subsidiaries' and our general partner's eligible officers (including the named executive officers), employees, consultants and directors will be eligible to receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to our performance. The description of the LTIP set forth below is a summary of the anticipated material features of the LTIP. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the LTIP. In addition, our general partner is still in the process of implementing the LTIP and, accordingly, this summary is subject to change prior to the effectiveness of the registration statement of which this prospectus is a part.

        The LTIP will provide for the grant, from time to time at the discretion of the board of directors or compensation committee of our general partner, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of                        common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited will be available for delivery pursuant to other awards. We expect that the LTIP will be administered by our general partner's board of directors, though such administration function may be delegated to a committee (including the compensation committee) that may be appointed by the board to administer the LTIP. The LTIP will be designed to promote our interests, as well as the interests of our unitholders, by rewarding the officers, employees, consultants and directors of us, our subsidiaries and our general partner for delivering desired performance results, as well as by strengthening our and our general partner's ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Restricted Units and Phantom Units

        A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

        Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

        The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

140

---

Unit Options and Unit Appreciation Rights

        The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

        Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

        Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

        The LTIP may also permit the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of an other unit-based award may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units; Cost

        Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Amendment or Termination of Long-Term Incentive Plan

        The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

141

---

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The following table sets forth certain information regarding the beneficial ownership of units following the closing of this offering and the related transactions by:

•

each person who is known to us to beneficially own 5% or more of such units to be outstanding;



•

our general partner;



•

each of the directors and named executive officers of our general partner; and



•

all of the directors and executive officers of our general partner as a group.

        All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

        The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of                        , 2012, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

142

---

        The percentage of units beneficially owned is based on a total of                        common units and                        subordinated units outstanding immediately following this offering.

143

---

144

---

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

        Immediately following the closing of this offering, Summit Investments will own                        common units and                         subordinated units, representing a combined        % limited partner interest in us (or                        common units and                        subordinated units, representing a combined         % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, Summit Investments will own and control our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to our General Partner and its Affiliates

        The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Summit Midstream Partners, LP These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Formation Stage

Operational Stage

145

---

Liquidation Stage

Agreements with Affiliates

        We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

Promissory Notes

        In conjunction with the purchase of the Grand River system, we executed promissory notes, on an unsecured basis, with Energy Capital Partners and GE Energy Financial Services. The notes totaled $200 million, have an 8% interest rate and mature on October 27, 2013. We have the option to elect to pay the interest in kind and we made this election for all interest due as of December 31, 2011. The amount of interest paid in kind and accrued to the balance of the note as of December 31, 2011 is $2.9 million resulting in $202.9 million as the amount outstanding on the notes as of December 31, 2011. As of December 31, 2011, the aggregate carrying value of these notes approximated the fair value.

EquiPower Electricity Management Services Agreement

        In December 2011, we entered into a consulting arrangement with EquiPower Resources Corp., or EquiPower, an affiliate of Energy Capital Partners, whereby EquiPower assists us with managing our electricity price risk. During the year ended December 31, 2011, we paid EquiPower $11,000 for such services. Curtis A. Morgan, a member of the board of directors of our general partner, is the President and Chief Executive Officer of EquiPower.

Procedures for Review, Approval and Ratification of Related-Person Transactions

        The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, the code of

146

---

business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

        The code of business conduct and ethics will provide that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

        The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

147

---

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

        Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Summit Investments), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.

        Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.

        Our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:

•

approved by the Conflicts Committee, although our general partner is not obligated to seek such approval;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;



•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        If the resolution or course of action taken with respect to the conflict of interest satisfies any of the standards set forth in the first, third or fourth bullet points above, then such resolution or course of action will be deemed to be approved by all of our unitholders and, in the case of all four bullet points above, will not constitute a breach of our partnership agreement or of any duties our general partner may owe us or our unitholders.

        Our general partner may, but is not required to, seek approval from the Conflicts Committee of a resolution of a conflict of interest with our general partner or affiliates. Any matters approved by the Conflicts Committee will be presumed to have been approved in good faith. If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and, in each case, in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he or she is acting in our best interest.

        Conflicts of interest could arise in the situations described below, among others.

148

---

Affiliates of our general partner may compete with us.

        Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, certain affiliates of our general partner, including Energy Capital Partners and GE Energy Financial Services, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, Energy Capital Partners and GE Energy Financial Services, through their investment funds and managed accounts, make investments and purchase entities in various areas of the energy sector, including the midstream natural gas industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, Energy Capital Partners and GE Energy Financial Services. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own an interest in entities that compete with us.

Our general partner is allowed to take into account the interests of parties other than us, such as Energy Capital Partners, in resolving conflicts.

        Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner's limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without those limitations, might constitute breaches of its fiduciary duty.

        In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. For example, our partnership agreement:

•

provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, which means the honest belief that the decision is in our best interest;



•

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2)"fair and reasonable" to us, as determined by our general partner in good faith, provided that, in determining whether a transaction or resolution is "fair and

149

---

reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

•

provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its executive officers or directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

        Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;



•

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;



•

the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;



•

the negotiation, execution and performance of any contracts, conveyances or other instruments;



•

the distribution of our cash;



•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;



•

the maintenance of insurance for our benefit and the benefit of our partners;



•

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;



•

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;



•

the indemnification of any person against liabilities and contingencies to the extent permitted by law;



•

the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and



•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

150

---

        Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in "good faith," our general partner must have an honest belief that the determination is in our best interests. Please read "The Partnership Agreement—Voting Rights" for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

        The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•

the amount and timing of asset purchases and sales;



•

cash expenditures and the amount of estimated reserve replacement expenditures;



•

borrowings;



•

the issuance of additional units; and



•

the creation, reduction or increase of reserves in any quarter.

        Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

        In addition, our general partner may use an amount, initially equal to $             million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

        In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or



•

hastening the expiration of the subordination period.

        For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

        We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services

151

---

provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read "Certain Relationships and Related Party Transactions."

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

        Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm's-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.

        Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.

        Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner's limited call right.

        Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

        Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

        The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general

152

---

partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our public common unitholders in certain situations.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distribution of Available Cash—General Partner Interest and Incentive Distribution Rights."

Fiduciary Duties

        Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify or eliminate, except for the contractual covenant of good faith and fair dealing, the fiduciary duties owed by the general partner to limited partners and the partnership.

        Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of our general partner's state-law fiduciary duty standards. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our

153

---

general partner in a manner beneficial both to its owners, as well as to our unitholders. Without these modifications, our general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

154

---

        By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

        Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read "The Partnership Agreement—Indemnification."

155

---

DESCRIPTION OF OUR COMMON UNITS

The Units

        The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

                                 will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by our unitholders:

•

surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;



•

special charges for services requested by a holder of a common unit; and



•

other similar fees or charges.

        There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

        The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

        By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;



•

represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and



•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

156

---

        Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

        We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

        Common units are securities and are transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

        Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

157

---

THE PARTNERSHIP AGREEMENT

        The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

        We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•

with regard to distributions of available cash, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions";



•

with regard to the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties";



•

with regard to the transfer of common units, please read "Description of Our Common Units—Transfer of Common Units"; and



•

with regard to allocations of taxable income and taxable loss, please read "Material Federal Income Tax Consequences."

Organization and Duration

        We were organized in Delaware in May 2012 and have a perpetual existence.

Purpose

        Our purpose under our partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

        Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than the business of gathering, compressing and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

        Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

Capital Contributions

        Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

        For a discussion of our general partner's right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read "—Issuance of Additional Securities."

158

---

Voting Rights

        The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a "unit majority" require:

•

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and



•

after the subordination period, the approval of a majority of the outstanding common units.

        By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

        In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.

159

---

Limited Liability

        Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

•

to remove or replace our general partner;



•

to approve some amendments to our partnership agreement; or



•

to take other action under our partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

        Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For

160

---

the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

        Our subsidiaries conduct business primarily in three states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

        Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

        Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.

        It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

        In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

        Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner's 2.0% interest in us will be reduced if we issue additional units in the future (other than in those circumstances described above) and our general partner does not

161

---

contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership securities.

Amendment of Our Partnership Agreement

General

        Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

        No amendment may be made that would:

•

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or



•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

        The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon the closing of this offering, affiliates of our general partner will own approximately        % of the outstanding common and subordinated units.

No Unitholder Approval

        Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;



•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;



•

a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our

162

---

operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•

a change in our fiscal year or taxable year and related changes;



•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;



•

an amendment that our general partner determines to be necessary or appropriate in connection with the authorization of issuance of additional partnership securities or rights to acquire partnership securities;



•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;



•

an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;



•

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;



•

mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or



•

any other amendments substantially similar to any of the matters described above.

        In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;



•

are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;



•

are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the units are or will be listed for trading;



•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or



•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

163

---

Opinion of Counsel and Limited Partner Approval

        Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under "—No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

        In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

        A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

        In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries' assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries' assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries' assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20.0% of our outstanding partnership securities immediately prior to the transaction.

        If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

164

---

Termination and Dissolution

        We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following the approval and admission of a successor general partner;



•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;



•

the entry of a decree of judicial dissolution of our partnership; or



•

there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

        Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•

the action would not result in the loss of limited liability of any limited partner; and



•

neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

        Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of Our General Partner

        Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to                        , 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                        , 2022 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days' advance notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest and incentive distribution rights in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" and "—Transfer of Incentive Distribution Rights."

165

---

        Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

        Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, and a majority of the outstanding subordinated units, voting as a single class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, affiliates of our general partner will own        % of the outstanding common and subordinated units.

        Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

•

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and



•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

        In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

        If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

        In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit.

166

---

Transfer of General Partner Interest

        Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

•

an affiliate of our general partner (other than an individual); or



•

another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity, our general partner may not transfer all or any of its general partner interest to another person prior to                         , 2022 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

        Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

        At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

        Our general partner or its affiliates or a subsequent holder may transfer any or all of its incentive distribution rights without unitholder approval.

Change of Management Provisions

        Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read "—Meetings; Voting."

Limited Call Right

        If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

•

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and



•

the average of the daily closing prices of the partnership securities of such class for the 20 consecutive trading days preceding the date three days before the date the notice is mailed.

167

---

        As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units."

Meetings; Voting

        Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

        Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

        Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

        Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

        By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

168

---

Non-Citizen Assignees; Redemption

        If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the nationality, citizenship or other related status of our member (and their owners, to the extent relevant); and



•

permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by our general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Taxpaying Assignees; Redemption

        In the event any rates that we charge our customers become regulated by the Federal Energy Regulatory Commission, to avoid any adverse effect on the maximum applicable rates chargeable to customers by us, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the U.S. federal income tax status of our member (and their owners, to the extent relevant); and



•

permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Indemnification

        Under our partnership agreement, we will indemnify the following persons, in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•

our general partner;



•

any departing general partner;



•

any person who is or was an affiliate of our general partner or any departing general partner;



•

any person who is or was a member, manager, partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

169

---

•

any person who is or was serving at the request of the general partner or any departing general partner as an officer, director, member, manager, partner, fiduciary or trustee of another person; and



•

any person designated by our general partner.

        Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

        Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

        Our general partner is required to keep or cause to be kept appropriate books and records of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.

        We will furnish or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants, including a balance sheet and statements of operations, and our equity and cash flows. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

        We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

        Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:

•

a current list of the name and last known business, residence or mailing address of each partner;



•

a copy of our federal, state and local income tax returns;

170

---

•

true and full information as to the amount of cash, and a description and statement of the net agreed value of any other capital contribution by each partner and that each partner has agreed to contribute in the future, and the date on which each became a partner;



•

copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;



•

information regarding the status of our business and financial condition; and



•

any other information regarding our affairs as is just and reasonable.

        Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

        Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years and for so long thereafter as is required for the holder to sell its partnership securities following any withdrawal or removal of Summit Midstream GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

171

---

UNITS ELIGIBLE FOR FUTURE SALE

        After the sale of the common units offered by this prospectus, Summit Investments will hold an aggregate of                        common units and                        subordinated units (or                        common units and                        subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

        The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1.0% of the total number of the securities outstanding; or



•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

        Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule's public information requirements, volume limitations, manner of sale provisions and notice requirements.

        Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."

        Under our partnership agreement, our general partner and its affiliates, excluding any individual who is an affiliate of our general partner, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

        Summit Investments, our general partner, each of our general partner's directors and officers and other owners have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Please read "Underwriting" for a description of these lock-up provisions.

172

---

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

        This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Summit Midstream Partners, LP and our operating subsidiaries.

        The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose "functional currency" is not the U.S. dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

        No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

        All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

        For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and

173

---

(iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").

Partnership Status

        A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than        % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

        No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•

We will be classified as a partnership for federal income tax purposes; and



•

Each of our operating subsidiaries will be disregarded as an entity separate from us for federal income tax purposes.

        In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

•

Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and



•

For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

        We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

        If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed

174

---

corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

        If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

        The discussion below is based on Latham & Watkins LLP's opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

        Unitholders of Summit Midstream Partners, LP will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes.

        A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

        Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding common units in Summit Midstream Partners, LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Summit Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

        Subject to the discussion below under "—Entity-Level Collections," we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

175

---

Treatment of Distributions

        Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units." Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

        A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

        We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending                                    , 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

        The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

176

---

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

        A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner's "net value" as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses

        The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

        In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

        In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in

177

---

other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

        A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

        The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;



•

our interest expense attributed to portfolio income; and



•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

        The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

        If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

        In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

178

---

        Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together referred to in this discussion as the "Contributed Property." The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, "reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

        An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•

his relative contributions to us;



•

the interests of all the partners in profits and losses;



•

the interest of all the partners in cash flow; and



•

the rights of all the partners to distributions of capital upon liquidation.

        Latham & Watkins LLP is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

        A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;



•

any cash distributions received by the unitholder as to those units would be fully taxable; and



•

all of these distributions would appear to be ordinary income.

179

---

        Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

        Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

        Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. These rates are scheduled to sunset after December 31, 2012, and, further, are subject to change by new legislation at any time.

        The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010 is scheduled to impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

        We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets ("common basis") and (ii) his Section 743(b) adjustment to that basis.

180

---

        We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Units."

        We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units." A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." Latham & Watkins LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

        A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

181

---

        The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

        We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Initial Tax Basis, Depreciation and Amortization

        The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

        To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read "—Uniformity of Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

        If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

        The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication

182

---

expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties.

        The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

        Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

        Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

        Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

        The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred.

183

---

Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

        Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;



•

an offsetting notional principal contract; or



•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

        Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

        In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

        Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under

184

---

future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

        A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

        We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

        Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be

185

---

inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under "—Tax Consequences of Unit Ownership—Section 754 Election," Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

        Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

        Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

        In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

186

---

        A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

        We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

        The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

        Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

        The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders

187

---

having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

        A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

        Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;



•

whether the beneficial owner is:



•

a person that is not a U.S. person;



•

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or



•

a tax-exempt entity;



•

the amount and description of units held, acquired or transferred for the beneficial owner; and



•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

        Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties.

        An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

        For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, "substantial authority"; or



•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

        If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take

188

---

other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

        A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

        In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions.

        If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

        Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties";



•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and



•

in the case of a listed transaction, an extended statute of limitations.

        We do not expect to engage in any "reportable transactions."

Recent Legislative Developments

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any such legislation could potentially affect us and may, if enacted, be applied retroactively. We are unable to predict whether any such legislation will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

189

---

State, Local, Foreign and Other Tax Considerations

        In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property and do business in Texas and Colorado. Colorado imposes a personal income tax on individuals, and both Texas and Colorado impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

        It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

190

---

INVESTMENT IN SUMMIT MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

        An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, "Similar Laws." For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements, collectively, "Employee Benefit Plans." Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;



•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;



•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read "Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors"; and



•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

        The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

        Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving "plan assets" with parties that, with respect to the Employee Benefit Plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

        In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

        The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed "plan assets." Under these rules, an entity's assets would not be considered to be "plan assets" if, among other things:

•

(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

191

---

•

(b) the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or



•

(c) there is no significant investment by "benefit plan investors," which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

        Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

        In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

192

---

UNDERWRITING

        Barclays Capital Inc. is acting as representative of the underwriters and as book-running manager of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

        The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

•

the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;



•

the representations and warranties made by us to the underwriters are true;



•

there is no material change in our business or the financial markets; and



•

we deliver customary closing documents to the underwriters.

Commissions and Expenses

        The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

        We will pay a structuring fee equal to        % of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. for the evaluation, analysis and structuring of our partnership.

        The representative of the underwriters has advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $            per common unit. After the offering, the representative may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters.

        We estimate that the expenses of this offering incurred by us will be $             million (excluding underwriting discounts and commissions and a structuring fee).

193

---

Option to Purchase Additional Common Units

        We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of                                    additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than                                    common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

        We, our general partner and its affiliates, including Summit Investments, and the directors and executive officers of our general partner have agreed that, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

        The 180-day restricted period described in the preceding paragraph will be extended if:

•

during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or



•

prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of the material event unless such extension is waived in writing by Barclays Capital Inc.

        Barclays Capital Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release the common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

Offering Price Determination

        Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated among the representative and us. In determining the initial public offering price of our common units, the representative will consider:

•

the history and prospects for the industry in which we compete;

194

---

•

our financial information;



•

the ability of our management and our business potential and earning prospects;



•

the prevailing securities markets at the time of this offering; and



•

the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

        We and certain of our affiliates, including Summit Investments, have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

        The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.



•

A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.



•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.



•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

        These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

195

---

        Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

        A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

        Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

        We intend to apply to list our common units on the New York Stock Exchange under the symbol "SMLP." The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

Discretionary Sales

        The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

        If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

        The underwriters and their affiliates have in the past, and may in the future, perform investment banking, commercial banking, advisory and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.

        In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations or publish or express independent research views in respect of

196

---

such securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

        An affiliate of Barclays Capital Inc. is a lender under our amended and restated revolving credit facility and, in that respect, will receive a portion of the net proceeds from this offering.

FINRA

        Because the Financial Industry Regulatory Authority, Inc., or FINRA, is expected to view the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

European Economic Area

        In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a "relevant member state"), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state, an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;



•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant dealer or dealers nominated by the issuer for any such offer; or



•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

        For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression "2010 PD Amending Directive" means Directive 2010/73/EU.

        We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

197

---

United Kingdom

        We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a "recognized collective investment scheme" for the purposes of FSMA, or CIS, and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

          (i)  if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended, or the CIS Promotion Order, or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

         (ii)  otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or Financial Promotion Order, or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

        (iii)  in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as "relevant persons"). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

        An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

Switzerland

        This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

        We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or the CISA. Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Germany

        This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention

198

---

to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

        The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Netherlands

        Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

199

---

VALIDITY OF THE COMMON UNITS

        The validity of the common units offered hereby will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

        The consolidated financial statements of Summit Midstream Partners, LLC and subsidiaries as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor) included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph related to Summit Midstream Partners, LLC's acquisition of (1) the Grand River system from Encana Corporation on October 27, 2011 and (2) DFW Midstream Services LLC from Energy Future Holdings Corp., effective September 3, 2009). Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The balance sheet of Summit Midstream Partners, LP included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC's web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

        As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website is located at                                    and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

        We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited

200

---

interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

        Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "will," "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

201

---

INDEX TO FINANCIAL STATEMENTS

F-1

---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC
Dallas, Texas

        We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LLC and subsidiaries (the "Company") as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, (Successor) and for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor), and for the period from January 1, 2009 through September 3, 2009 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 4 to the consolidated financial statements, the Company acquired Grand River Gathering Company, LLC on October 27, 2011. Also, as discussed in Note 3 to the consolidated financial statements, the Company acquired a controlling interest in DFW Midstream Services LLC on September 3, 2009.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-2

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-3

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-4

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

 

   

The accompanying notes are an integral part of these consolidated financial statements.

F-5

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

F-6

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-7

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

        Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009 (inception). The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B Units in Summit Midstream through their ownership in Summit Midstream Management, LLC.

        Concurrent with the Company's formation on September 3, 2009, the Company acquired a controlling interest in DFW Midstream Services LLC ("DFW Midstream"), and accordingly, the DFW Midstream Limited Liability Company Agreement was amended and restated to effect among other things (i) the continuation of Texas Competitive Electric Holdings Company LLC ("TCEH") as a Class A Member, (ii) the admission of Summit Midstream as a Class A Member, (iii) the admission of DFW Midstream Management LLC as the Class B Member, and (iv) the continuation of DFW Midstream as a Delaware limited liability company. The acquisition of a controlling interest in DFW Midstream by Summit Midstream was accounted for under the acquisition method of accounting. Summit Midstream's consolidated financial statements reflect DFW Midstream's operations for all periods presented.

        On June 2, 2010, Summit Midstream purchased all of TCEH's remaining membership interests in DFW Midstream. The transaction was completed on June 18, 2010. The purchase of the remaining noncontrolling interest in DFW Midstream was accounted for as an equity transaction (see Note 10).

        On October 4, 2011 the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10-25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development. The transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

F-8

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream and Grand River Gathering. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

        Basis of Presentation—The consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The consolidated financial statements for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, reflect the application of purchase accounting related to the acquisition of a controlling interest in DFW Midstream by Summit Midstream on September 3, 2009. The consolidated financial statements also include the operations of Grand River Gathering upon the closing of the transaction on October 27, 2011.

        The consolidated financial statements provided for the period from January 1, 2009 through September 3, 2009, include only the operations of DFW Midstream which is the predecessor of Summit Midstream. These financial statements represent the results of operations, changes in membership interest and cash flows of DFW Midstream and have been carved out of the accounting records maintained by Energy Future Holdings Corp. and its subsidiaries ("Energy Future Holdings"). Historically, Energy Future Holdings did not allocate general and administrative ("G&A") expenses to DFW Midstream for any centralized finance and administrative costs. Accordingly, the financial statements for the period from January 1, 2009 through September 3, 2009 (inception) include an estimate of G&A for the period of $588 based on the level of significance of DFW Midstream to Energy Future Holdings, the number of employees directly involved in DFW Midstream and considering the capital intensive nature of the activities of DFW Midstream during this period. The estimate of G&A expenses was predominantly related to rent, insurance and other employee related expenses. Because of the nature of these carved-out financial statements, the intercompany advances from Energy Future Holdings were reported within an intercompany advances account, and immediately prior to the acquisition, were converted to membership interest.

        All intercompany transactions have been eliminated upon consolidation. Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

        The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

F-9

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Use of Estimates—The consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

        Cash and Cash Equivalents—Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

        Accounts Receivable—Accounts receivable relate to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At December 31, 2011 and 2010, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for services during any period presented.

        Intangible Assets and Liabilities—Intangible assets and unfavorable contracts consisting of favorable and unfavorable gas gathering contracts are amortized on a units-of-production basis over the life of the contract, which is the period over which the contracts are expected to contribute directly or indirectly to the Company's future cash flows. The favorable and unfavorable contracts relate to gas gathering contracts that were deemed to be above or below market at the acquisition of DFW Midstream. The contract lengths range from 10 years to 20 years.

        Intangible assets consisting of contract values related to the Grand River Gathering gas gathering agreements are amortized over the period of economic benefit based upon the expected revenues over the life of the contract, which range from 10 years to 25 years.

        Right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way are amortized over the shorter of the contractual term of the rights-of-way, ranging from 20 years to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        Property, Plant, and Equipment—Property, plant, and equipment are recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

F-10

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

        Impairment of Long-Lived Assets—Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows. The Company did not recognize any impairment of long-lived assets during any period presented.

        Other Noncurrent Assets—Other noncurrent assets primarily consist of external costs incurred in connection with the closing of the Company's revolving credit facility and costs incurred related to the Company's contemplated initial public offering. Deferred loan costs are capitalized and amortized over the life of the related agreement. Amortization of deferred loan costs is included in interest expense in the statement of operations.

        Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether any future asset retirement obligations exist as of December 31, 2011 and 2010, and whether the expected retirement date of the related costs of retirement can be estimated. In the Company's judgment, the timing and cost of any future asset retirement obligation cannot be determined as of December 31, 2011 and 2010.

        Revenue Recognition—The Company earns revenue from natural gas gathering services provided to natural gas producers and records such revenue as gathering services and other fees. The Company also earns revenue from the sale of physical natural gas retained from its customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. The Company records this revenue as natural gas and condensate sales. The Company records costs incurred which are reimbursed by its customers, on a gross basis in the consolidated statements of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured.

        Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are

F-11

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 8 for a discussion of commitments and contingencies.

        Environmental Matters—The operations of the Company and the Predecessor are subject to various federal, state and local laws and regulations relating to the protection of the environment. Although the Company believes that it is in compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation, and there can be no assurances that significant costs and liabilities will not be incurred by the Company. Management is not aware of any contingent liabilities that currently exist with respect to environmental matters.

        Income Taxes—Provision for income taxes is attributable to the Company's state tax obligations under the gross margin tax enacted by the State of Texas. Since the Company is structured as a partnership for federal income tax purposes, the Company is not subject to federal income taxes. As a result, the Company's members are individually responsible for paying federal income taxes on their share of the Company's taxable income. See Note 9 for additional information regarding the Company's income taxes.

        Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

        Comprehensive Income (Loss)—Comprehensive income (loss) is the same as net income (loss) for all periods presented.

        Earnings Per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

        Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its consolidated financial statements.

        Unit Based Compensation—Certain of our current and former employees received Class B membership interests, which are net profits interests, in DFW Midstream Management, LLC or Summit Midstream Management, LLC. The Class B units participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Class B members. The Class B units are accounted for as compensatory awards. The grants vest ratably over four to five years. We determined the fair value of the Class B units as of the respective grant dates. The Class B units were valued utilizing an option pricing method, which models the Class A and Class B units as call options on the underlying equity value considering the rights and preferences of

F-12

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

each class of equity to allocate a fair value to each class. The significant inputs used in the option pricing method are the length of holding period restriction, the discount for lack of marketability and volatility.

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM

        On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from TCEH (the "DFW Transaction"). At the date of the DFW Transaction, the Company received a capital contribution from Energy Capital Partners of $107,000 and contributed $85,082 to DFW Midstream in exchange for a 75% membership interest. Concurrently, DFW Midstream purchased certain natural gas gathering assets under construction located in the Barnett Shale from a division of Chesapeake Energy Corporation for $44,896, and a distribution of $40,186 was made by DFW Midstream to TCEH.

        The Company accounted for the DFW Transaction under the acquisition method of accounting, whereby the total purchase price of the DFW Transaction was allocated to DFW Midstream's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of September 3, 2009. The intangible assets acquired were right-of-way easements (weighted average life of 28.6 years) and favorable gas gathering agreements (weighted average life of 18.7 years). The intangible liabilities acquired were unfavorable gas gathering agreements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete DFW Midstream's gathering system. The purchase price was estimated by imputing the value of 100% of the membership interests in DFW Midstream based upon $85,082 in cash contributed by Summit Midstream in exchange for an economic interest in DFW Midstream equal to 70.5% of future distributions and the obligation to contribute 75% of the project completion budget. The purchase price was equal to the fair value of the net assets of DFW Midstream; thus, no goodwill was recorded.

F-13

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

        Fair values of the assets acquired and liabilities assumed as of September 3, 2009 are as follows:

        The fair value of the noncontrolling interest in DFW Midstream held by TCEH at September 3, 2009, was estimated based on TCEH's economic interest in DFW Midstream equal to 29.5% of future distributions and the obligation to contribute 25% of the project completion budget, with adjustments because of the lack of control and lack of marketability that market participants would be expected to consider when estimating the fair value of the noncontrolling interest in DFW Midstream.

        In connection with the DFW Transaction, the Company incurred $3,921 in transaction costs, which were expensed as incurred and are reported within transaction costs. Such costs include $1,075 paid to Energy Capital Partners Management II, LP, a related party; $1,103 paid to Energy Capital Partners Management LP, a related party; and $1,743 paid to third parties (of which $1,603 was paid by Energy Capital Partners on behalf of the Company) for strategic, advisory, management, legal, and consulting services. Transaction costs paid by Energy Capital Partners are presented as a noncash capital contribution.

4. ACQUISITION OF GRAND RIVER GATHERING

        The Company completed the acquisition of Grand River Gathering from Encana for $590 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 260 miles of pipeline and 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana

F-14

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development.

        The Grand River Transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly-owned subsidiary of the Company. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million. For the period ended December 31, 2011, the Company recorded $12,824 of revenue and $2,111 of net income related to Grand River Gathering.

        The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete Grand River Gathering's gathering system. The Company has not completed the final purchase price allocation to the assets acquired and liabilities assumed as of December 31, 2011, because the Company is waiting to receive certain information in order to complete its determination of the values of acquired assets under construction, the related impacts on the valuation of the customer contract intangible assets and the final settlement of the purchase price.

        Fair values of the assets acquired and liabilities assumed as of October 27, 2011 are as follows:

        The Company determined that the purchase price was equal to the fair value of the net assets acquired; thus, no goodwill was recorded.

        Unaudited Pro Forma Financial Information—The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010 and the

F-15

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

DFW Midstream acquisition (see Note 3) occurred on January 1, 2009. Transaction costs of $3,160 related to the acquisition of Grand River Gathering have been adjusted and recorded in 2010 for the proforma information below. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the transactions had occurred on those dates, or what the Company's financial position or results from operations will be for any future periods.

        Pro forma adjustments for the year ended December 31, 2011 consist of $64,119 of revenue and $11,610 of net income for January through October of 2011 and $76,943 of revenue and $12,665 for the year ended December 31, 2010 related to Grand River Gathering assuming the acquisition date was January 1, 2010. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that we recorded for the two month period from November 1, 2011 through December 31, 2011. The transaction costs of $3,160 have been removed from the year ended December 31, 2011 and reflected in the year ended December 31, 2010. Pro forma adjustments for the year ended December 31, 2009 represent $39 of revenue and $654 of depreciation related to DFW Midstream assuming the DFW Transaction was effective January 1, 2009.

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY

        The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable intangible assets and a noncurrent liability, which are subject to amortization as of December 31, 2011 and 2010, are composed of the following:

F-16

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

        Amortization expense of $1,718, $764, $40, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

        Amortization expense of $2,412 for the year ended December 31, 2011 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in the depreciation and amortization expense in the statement of operations. The intangible asset contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

        Amortization expense of $908, $519, $114, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to rights-of-way associated with city easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        The unfavorable contract included within noncurrent liability relates to an unfavorable gas gathering contract that was deemed to be below market upon the acquisition of DFW Midstream. Amortization related to the unfavorable gas gathering contract was $1,410, $549, $60, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within revenue. The unfavorable contract is amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

F-17

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

        The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from December 31, 2011 is as follows:

        There are no indefinite-lived intangible assets recorded as of December 31, 2011 or 2010.

6. PROPERTY, PLANT, AND EQUIPMENT—NET

        Net property, plant, and equipment as of December 31, 2011 and 2010, is composed of the following:

        Depreciation expense related to property, plant, and equipment was $8,595, $3,355, $230, and $882 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively. The Company capitalized interest totaling $3,362 during the year ended December 31, 2011 and zero in any other period.

7. REVOLVING CREDIT FACILITY

        On May 26, 2011, Holdings closed a senior secured revolving credit facility with total commitments of $285 million. The revolving credit facility, which matures in May 2016, contains a $150 million accordion provision that enables Holdings to increase the total size of the facility any time prior to

F-18

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

7. REVOLVING CREDIT FACILITY (Continued)

maturity. The revolving credit facility allows for revolving loans, letters of credit and swingline loans. The revolving credit facility is secured by the membership interests of Holdings and DFW Midstream and substantially all of Holdings' and DFW Midstream's assets and is guaranteed by Holdings' subsidiaries. Borrowings under the revolving credit facility bear interest at London Interbank Offered Rate ("LIBOR") plus an applicable margin or a base rate, as defined in the credit agreement. Under the terms of the revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at December 31, 2011. As of December 31, 2011, availability under the revolving credit facility totaled $138 million. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of December 31, 2011 was 2.88%.

        The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of December 31, 2011, Holdings was in compliance with all applicable covenants.

        The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners. As of December 31, 2011, there was $147 million outstanding under the facility.

        On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed $163 million under the facility. As of May 11, 2012, we had $307 million of indebtedness under our revolving credit facility. Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. The amended and restated revolving credit facility matures in May 2016.

F-19

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

8. PROMISSORY NOTES PAYABLE TO SPONSORS

        In conjunction with the purchase of Grand River Gathering, the Company executed promissory notes, on an unsecured basis, with its Sponsors. The notes totaled $200 million, mature on October 27, 2013 and have an 8% interest rate. The Company has the option to elect to pay the interest in kind and the Company made this election for all interest due as of December 31, 2011. The amount of interest paid in kind and accrued to the balance of the notes as December 31, 2011 is $2,893, resulting in $202,893 as the amount outstanding on the note as of December 31, 2011. During 2011, the Company capitalized $868 of the $2,893 interest expense related to costs incurred on capital projects under construction. As of December 31, 2011, the aggregate carrying value of these notes approximated the fair value. On May 7, 2012, the Company amended and restated its revolving credit facility. On May 8, 2012, the Company borrowed $163 million under the amended and restated revolving credit facility and used the same borrowings to prepay $160 million of the promissory notes payable to Sponsors. As of May 11, 2012, the balance under the promissory notes payable to Sponsors was $48,695.

9. INCOME TAXES

        In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $695, $124, $7, and $8, for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively.

10. MEMBERSHIP INTERESTS

        As described in Note 1, Summit Midstream is controlled by Energy Capital Partners through Energy Capital Partners' ownership of Class A membership interests in the Company. On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to GE Energy Financial Services, therefore as of December 31, 2011 Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. As of December 31, 2010 and 2009, Energy Capital Partners held all of the Company's membership interests. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

        In accordance with the Summit LLC Agreement, capital accounts are maintained for the Company's members. The capital account provisions of the Summit LLC Agreement incorporate

F-20

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

        The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests.

        In addition, contemporaneously with the formation of Summit Midstream and the execution of the Summit LLC Agreement at September 3, 2009, and on April 1, 2010, April 1, 2011 and October 18, 2011 certain members of Summit Midstream Management, LLC, who are employees of the Company, received Class B membership interests (or "Net Profits Interests"), which participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Class B members. The Class B units are accounted for as compensatory awards. The grants vest ratably over 5 years.

        During the year ended December 31, 2011, the Company determined the fair value of the Class B units as of the respective grant dates. The Class B units were valued utilizing an option pricing method, which models the Class A and Class B units as call options on the underlying equity value considering the rights and preferences of each class of equity to allocate a fair value to each class. The significant inputs used in the option pricing method for the Summit Midstream Class B units are as follows for the three years in the period ended December 31, 2011:

        The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $1,269 which included $463 related to years prior to 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 3.2 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $3,971.

        The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests described above.

        In connection with the Company's formation and acquisition of DFW Midstream on September 3, 2009, Energy Capital Partners contributed $107,000 to the Company in order to initially capitalize the Company and fund the Company's investment in DFW Midstream. Energy Capital Partners contributed

F-21

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

an additional $27,871 of capital to Summit Midstream through December 31, 2009. Energy Capital Partners made cash contributions of $194,134 to the Company for the year ended December 31, 2010, which were primarily used to fund ongoing capital expenditures of DFW Midstream and purchase the remaining noncontrolling interest in DFW Midstream from TCEH on June 18, 2010, as discussed below.

        In connection with the closing of the Company's revolving credit facility in May 2011, the Company distributed $132,943 to Energy Capital Partners.

        Noncontrolling Interest in DFW Midstream—During the three years ended December 31, 2011, the Company has had several changes in membership interests related to the ownership of its consolidated subsidiary DFW Midstream as discussed further below. At December 31, 2011 and 2010, 100% of the Class A membership interests of DFW Midstream were held by Summit Midstream or its direct subsidiary, Holdings. Summit Midstream, through its subsidiary Holdings, as the sole Class A Member, holds units that represent membership interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement (collectively the "LLC Agreement"). The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive.

        In accordance with the LLC Agreement, capital accounts are maintained for the members. The capital account provisions of the LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

        The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive. Prior to Summit's purchase of TCEH's remaining interest in DFW Midstream on June 18, 2010 (as discussed immediately below), Summit held a 75% interest and TCEH held a 25% Class A membership interest; however, distributions and allocations of income and loss are based on a sharing percentage as defined in the LLC Agreement resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit and TCEH, respectively. Capital contributions required under the LLC Agreement are in proportion to the owners' respective percentage ownership interests.

        In 2010, Summit Midstream and TCEH entered into a Membership Interest Purchase Agreement whereby Summit Midstream purchased all of TCEH's membership interests in DFW Midstream for cash consideration of $90,722. Amounts reported as noncontrolling interest relate to TCEH's ownership interests in DFW Midstream prior to June 18, 2010. The change in Summit Midstream's ownership interest in DFW Midstream resulted in a decrease in membership interest of $25,126 for the year ended December 31, 2010, as the cash consideration paid exceeded the carrying value of the noncontrolling interest at June 18, 2010.

F-22

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        Distributions and allocations of income and loss for the periods presented prior to June 18, 2010, are based upon a sharing percentage as defined in the Amended and Restated LLC Agreement of DFW Midstream resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit Midstream and TCEH, respectively. Net income (loss) of $78 and $(400) was allocated to TCEH, as the noncontrolling interest holder, based upon its ownership interests and profits and losses allocation for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively.

        TCEH funded capital contributions in the amount of $10,720 and $15,417 for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively. Additionally, in connection with the Company's acquisition of DFW Midstream on September 3, 2009, DFW Midstream distributed $40,186 to TCEH as a return of capital.

        In addition, contemporaneously with the execution of the LLC Agreement on September 3, 2009 and on April 1, 2010, and July 28, 2010, certain current and former members of DFW Midstream Management LLC received Class B membership units totaling up to 5% membership interests, which participate in distributions upon vesting and the achievement of certain distribution targets to Class A members or higher priority vested Class B members. The Class B membership units are accounted for as compensatory awards. The grants vest ratably over 4 years.

        During the year ended December 31, 2011, the Company determined the fair values of the Class B units as of the respective grant dates on the respective grant dates. The Class B units were valued utilizing an option pricing method, which models the Class A and Class B units as call options on the underlying equity value considering the rights and preferences of each class of equity to allocate a fair value to each class. The significant inputs used in the option pricing method for the DFW Midstream Class B units are as follows for the three years in the period ended December 31, 2011:

        The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $2,171 which included $582 related to years prior to 2011. During the year ended December 31, 2011, the Company modified the awards to remove a rate of return payout hurdle and as a result of the modification; the Company valued the Class B Units immediately prior to and following the modification to determine incremental compensation expense. The modification resulted in the immediate expense of $1,358 attributed to the previously vested Class B Units which is included in the $1,589 of compensation expense recorded during the year ended December 31, 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of

F-23

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

2.1 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $1,321.

        Predecessor Membership Interests—Prior to the DFW Transaction, TCEH funded the Company's construction activities and working capital needs through intercompany loans or advances that accrued interest at an average rate of 4.29% for the predecessor period. Immediately prior to the DFW Transaction, the advances were converted to a membership interest.

11. COMMITMENTS AND CONTINGENCIES

        Contractual Commitments—The Company leases office space for its headquarters in Dallas, Texas and for other offices in Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas, and has determined that its leases are classified as operating leases. A schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011 is as follows:

        Total rent expense related to operating leases was $489, $212, $28, and $0 for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) to December 31, 2009, the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within general and administrative.

        Legal Proceedings—The Company is involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on the Company's financial condition, results of operations, or liquidity.

12. RELATED-PARTY TRANSACTIONS

        Transaction Costs—As discussed in Note 3, during 2009 the Company paid transaction costs of $1,075 and $1,103 to Energy Capital Partners Management II, LP and Energy Capital Partners Management, LP, respectively.

        Diligence Expenses—The Sponsors agreed to reimburse the Company for previous transactional due diligence expenses related to proposed transactions that were not completed. As of December 31, 2011, the Company had a receivable from the Sponsors of $1,309 related to this previous agreement.

F-24

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. RELATED-PARTY TRANSACTIONS (Continued)

        Transition Services Agreement—The Company executed a transition services agreement with TCEH effective September 3, 2009. The services provided to the Company by TCEH included the temporary use of TCEH office space; ongoing utilization of accounting and financial reporting services support; general support regarding any administration of Consolidated Omnibus Budget Reconciliation Act (COBRA) health benefits; general information technology support to manage data files, addresses, network connectivity, etc.; and use of computers, right-of-way services, and public relation services. The costs and rates charged to the Company by TCEH related to each service were negotiated and mutually agreed to by both parties. The termination date related to each service provided under the agreement varies with the option to extend certain services if deemed necessary and agreed to by both parties. The extension periods are in three-month intervals beginning January 1, 2010, and are limited to 18 months in total. As of December 31, 2011, the only services provided under the agreement that remain relate to the right-of-way services. The amounts charged to the Company through the transition services agreement for the years ended December 31, 2011 and 2010 and for the period from September 3, 2009 (inception) through December 31, 2009, were $39, $137 and $100, respectively.

        Promissory Notes—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 8)

        Electricity Management Services Agreement—The Company entered into a consulting arrangement with EquiPower Resources Corp. ("EquiPower"), an affiliate of Energy Capital Partners, whereby EquiPower assists the Company with managing its electricity price risk. During the years ended December 31, 2011 and 2010, the Company paid EquiPower $11 and zero for such services, respectively.

13. CONCENTRATIONS OF RISK

        Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and accounts receivable. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.

        Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale of natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the Company's customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

        For the years ended December 31, 2011 and 2010, the Company had four customers (each comprising over 10% of total revenue) that accounted for approximately 73% and 88% of total gas

F-25

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

13. CONCENTRATIONS OF RISK (Continued)

revenue, respectively. The total accounts receivable from these customers accounted for approximately 66% and 95% of accounts receivable for the years ended December 31, 2011 and 2010, respectively.

        The following tables summarize concentrations of revenue and accounts receivable in excess of 10% of total revenue and accounts receivable as of and for the years ended December 31, 2011 and 2010, for the period from September 3, 2009 (inception) through December 31, 2009 and for the period from January 1, 2009 through September 3, 2009, respectively:

******

F-26

---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC as general partner of Summit Midstream Partners, LP
Dallas, Texas

        We have audited the accompanying balance sheet of Summit Midstream Partners, LP (the "Partnership") as of May 10, 2012. The balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on the balance sheet based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Partnership as of May 10, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-27

---

SUMMIT MIDSTREAM PARTNERS, LP

BALANCE SHEET

MAY 10, 2012

F-28

---

SUMMIT MIDSTREAM PARTNERS, LP

NOTE TO BALANCE SHEET

1. Nature of Operations

        Summit Midstream Partners, LP (the "Partnership") is a Delaware limited partnership formed on May 1, 2012 to acquire certain assets and related contracts and agreements from the operating subsidiaries of Summit Midstream Partners, LLC. In order to simplify the Partnership's obligations under the laws of selected jurisdictions in which the Partnership will conduct business, the Partnership's activities will be conducted through a wholly owned limited liability company.

        Summit Midstream GP, LLC, as general partner, contributed $20 and Summit Midstream Partners, LLC, as the organizational limited partner, contributed $980 to the Partnership on May 10, 2012.

2. Summary of Significant Accounting Policies

Basis of Presentation

        This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America. Separate statements of operations, membership interests, and cash flows have not been presented because the entity has had no business transactions or activities to date.

Subsequent Events

        Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

3. Commitments and Contingencies

        As of the date of these financial statements, Summit Midstream Partners, LP had no outstanding commitments and contingencies.

F-29

---

APPENDIX A
FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF
SUMMIT MIDSTREAM PARTNERS, LP

To be filed by amendment.

A-1

---

APPENDIX B
GLOSSARY OF TERMS

        condensate:    A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

        dry gas:    A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

        end users:    The ultimate users and consumers of transported energy products.

        Mcf:    One thousand cubic feet.

        MMBtu:    One million British Thermal Units.

        MMBtu/d:    One million British Thermal Units per day.

        MMcf:    One million cubic feet.

        MMcf/d:    One million cubic feet per day.

        NGLs:    Natural gas liquids. The combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

        NYMEX:    New York Mercantile Exchange.

        play:    A proven geological formation that contains commercial amounts of hydrocarbons.

        receipt point:    The point where production is received by or into a gathering system or transportation pipeline.

        residue gas:    The natural gas remaining after being processed or treated.

        tailgate:    Refers to the point at which processed natural gas and natural gas liquids leave a processing facility for end-use markets.

        Tcf:    One trillion cubic feet.

        throughput volume:    The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

        wellhead:    The equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.

B-1

---

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

---

Prospectus

                         , 2012

---

Barclays

        Until                    , 2012 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

---

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        Set forth below are the expenses (other than underwriting discounts, commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

Item 14.    Indemnification of Directors and Officers.

Summit Midstream Partners, LP

        Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

        The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Summit Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Summit Midstream GP, LLC

        Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

        Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

II-1

---

•

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;



•

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and



•

any person designated by our general partner.

        Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15.    Recent Sales of Unregistered Securities.

        On May 10, 2012, in connection with the formation of Summit Midstream Partners LP, we issued (i) the 2.0% general partner interest in us to Summit Midstream GP, LLC for $20, and (ii) a 98% limited partner interest in us to Summit Midstream Partners, LLC for $980, in each case in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

Item 16.    Exhibits and Financial Schedules.

        The following documents are filed as exhibits to this registration statement:

II-2

---

Item 17.    Undertakings

        The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

        Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

        The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.



(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.



(3)

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

II-3

---

(4)

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

          (i)  Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

         (ii)  If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use;

        (iii)  Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

        (iv)  The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

         (v)  Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

        The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Summit Midstream GP, LLC our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Summit Midstream GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

        The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-4

---

SIGNATURES

        Pursuant to the to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on [    •    ], 2012.

        Each person whose signature appears below appoints Steven J. Newby and Brock M. Degeyter, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

II-5

---

        Pursuant to the requirements of the Securities Act of 1933, as amended this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

II-6

---

EXHIBIT INDEX

        The following documents are filed as exhibits to this registration statement:

---

Exhibit 99.2

          As confidentially submitted to the Securities and Exchange Commission on July 17, 2012

Registration No. 333-                        

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Confidential Draft Submission No. 2

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Summit Midstream Partners, LP
(Exact Name of Registrant as Specified in its Charter)

2100 McKinney Avenue
Suite 1250
Dallas, Texas 75201
(214) 242-1955
(Address, including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

Brock M. Degeyter
Senior Vice President and General Counsel
2100 McKinney Avenue
Suite 1250
Dallas, TX 75201
(214) 242-1955
(Name, Address, including Zip Code, and Telephone Number, including
Area Code, of Agent for Service)

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

          If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

          If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

          If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

          If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

CALCULATION OF REGISTRATION FEE

(1)

Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   

---

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated July 17, 2012

PROSPECTUS

---

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

---

This is the initial public offering of our common units representing limited partner interests. We are offering             common units in this offering. We currently expect that the initial public offering price will be between $             and $             per common unit. Prior to this offering, there has been no public market for our common units.

We intend to apply to list our common units on the New York Stock Exchange under the symbol "SMLP."

We are an "emerging growth company" as defined in Section 101 of the Jumpstart Our Business Startups Act, or JOBS Act.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 20.

These risks include the following:

•

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.



•

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 and for the twelve months ended March 31, 2012.

•

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.



•

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.



•

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to our unitholders over the long-term.



•

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.



•

Summit Midstream Partners, LLC, which we refer to as "Summit Investments," owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and has limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other unitholders.



•

Our partnership agreement restricts the rights of holders of our common units with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.



•

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.



•

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.



•

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

We have granted the underwriters the option to purchase up to an additional             common units on the same terms and conditions set forth above if the underwriters sell more than              common units in this offering.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about                    , 2012, through the book-entry facilities of The Depository Trust Company.

---

---

Prospectus dated                    , 2012

---

---

      

TABLE OF CONTENTS

i

---

ii

---

        You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making

iii

---

an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

Industry and Market Data

        The data included in this prospectus regarding the midstream natural gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management's knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management's knowledge and experience we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.

iv

---

      

1

---

 

2

---

 

3

---

 

4

---

 

5

---

 

6

---

 

7

---

 

8

---

 

9

---

      

10

---

 

11

---

 

12

---

     

13

---

 

14

---

 

15

---

 

16

---

17

---

 

18

---

 

19

---

RISK FACTORS

        Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were to materialize, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common and subordinated units.

        In order to pay the minimum quarterly distribution of $            per unit per quarter, or $            per unit on an annualized basis, we will require available cash of approximately $             million per quarter, or $             million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the volume of natural gas we gather and compress;



•

the level of production of natural gas from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, natural gas and natural gas liquids, or NGLs;



•

damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism;



•

leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise;



•

changes in the fees we charge for our services;



•

the level of competition from other midstream energy companies in our geographic markets;



•

changes in the level of our operating, maintenance and general and administrative costs;



•

regulatory action affecting the supply of, or demand for, natural gas, the fees we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and



•

prevailing economic and market conditions.

        In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

•

the level and timing of capital expenditures we make;

20

---

•

the level of our operating and general and administrative expenses, including reimbursements to our general partner for services provided to us;



•

the cost of acquisitions, if any;



•

our debt service requirements and other liabilities;



•

fluctuations in our working capital needs;



•

our ability to borrow funds and access capital markets;



•

restrictions contained in our debt agreements;



•

the amount of cash reserves established by our general partner; and



•

other business risks affecting our cash levels.

        For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2011 and for the twelve months ended March 31, 2012.

        We must generate approximately $             million of available cash to pay the minimum quarterly distribution for four quarters on all of our common and subordinated units that will be outstanding immediately following this offering, as well as the corresponding distribution on our 2.0% general partner interest. The amount of cash available for distribution that we generated during the year ended December 31, 2011 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of our subordinated units for that period. In addition, the amount of cash available for distribution that we generated during the twelve months ended March 31, 2012 would have been sufficient to pay the full minimum quarterly distribution on all common units but only a cash distribution of $            per quarter ($            on an annualized basis), or approximately        % of the minimum quarterly distribution, on all of our subordinated units for that period. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Our Cash Distribution Policy and Restrictions on Distributions."

The assumptions underlying the forecast of cash available for distribution that we include in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The forecast of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending June 30, 2013. We estimate that our total cash available for distribution for the twelve months ending June 30, 2013 will be approximately $85.9 million, as compared to approximately $39.8 million for the year ended December 31, 2011 and approximately $49.3 million for the twelve months ended March 31, 2012 on a historical as adjusted basis. The significant expected increase in cash available for distribution is primarily attributable to the inclusion of the Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011 and for only five months during the twelve months ended March 31, 2012. To the extent that volumes on either the Grand River system or the DFW Midstream system are lower than we project, our revenues during the forecast period will be adversely affected. If the actual volume of natural gas we gather on our systems for the twelve months ending June 30, 2013 is 10%

21

---

lower than our forecast, we expect we would have sufficient cash available to pay the full distribution to holders of our common units and only        % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our revenues, cash flow and ability to make distributions to our unitholders.

        A significant percentage of our revenue is attributable to a relatively small number of customers. Chesapeake, Carrizo Oil & Gas, Inc., or Carrizo, and TOTAL accounted for approximately 34%, 17% and 10%, respectively, of our revenue for the year ended December 31, 2011. Encana, Carrizo and Chesapeake accounted for approximately 31%, 18% and 16%, respectively, of our revenue for the three months ended March 31, 2012. If our customers curtail or reduce production in our areas of operation it could reduce throughput on our system and, therefore, adversely affect our revenues, cash flow and ability to make distributions to our unitholders. For example, in January 2012 Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region as well as reduce its dry gas production by up to 500 MMcf/d. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011 primarily as a result of Chesapeake's publicly announced reduction in production. Please read "—Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve."

        Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenue and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue. In addition, if any one or more of our gas gathering agreements that account for 25% or more of our revenues are terminated, and such termination is reasonably expected to have a Material Adverse Effect (as defined in our amended and restated revolving credit facility), and a replacement agreement is not obtained within 30 days, this would constitute an event of default under our amended and restated revolving credit facility and our lenders would be able to accelerate payment of the debt outstanding thereunder.

We gather natural gas from the Piceance Basin and the Barnett Shale. Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

        Our operations are focused on natural gas gathering and compression services. Our assets are located exclusively in the Piceance Basin in western Colorado and the Barnett Shale region in north-central Texas and we intend to focus our future capital expenditures largely on developing our business

22

---

in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of industrial and geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. For example, a significant portion of the gas we gather in the Piceance Basin and the Barnett Shale is dry gas. Due to recent declines in natural gas prices, several of our customers have substantially reduced their dry gas production in these regions and announced their intent to reduce capital expenditures for dry gas drilling activities.

        A significant portion of our operations are concentrated in the Barnett Shale region, which could disproportionately expose us to operational and regulatory risk in that area. The location of the Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for natural gas in urban and suburban communities. The DFW Midstream system is within the city limits of various municipalities in that region, including Arlington, Texas. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs, which has led producers to pursue a high density pad site drilling strategy. Furthermore, the process of obtaining permits for constructing additional gathering lines to deliver our customers' natural gas to market may be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and materially adversely affecting our revenues and cash available to make distributions to you over the long-term.

        Lower natural gas prices over the long-term could result in a decline in the production of natural gas resulting in reduced throughput on our systems. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $2.42 per MMBtu as of May 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration, the EIA, average annual natural gas production in the United States increased 14.1% from 55.2 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.2 Tcf as of June 3, 2011 to approximately 2.9 Tcf as of June 1, 2012, due to the unseasonably warm winter of 2011/2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 515 as of May 31, 2012 according to Smith Bits (a unit of Schlumberger Limited), as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

        The decline in natural gas prices has had a negative impact on exploration, development and production activity in our areas of operation. If natural gas prices remain depressed or decrease further, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        Also, higher natural gas prices over the long-term could result in a decline in the demand for natural gas and, therefore, in the throughput on our systems. As a result, significant prolonged changes

23

---

in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes of natural gas that we gather could materially adversely affect our business and operating results.

        The natural gas volumes that support our business depend on the level of production from natural gas wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.

        We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

•

the availability and cost of capital;



•

prevailing and projected commodity prices, including the prices of oil, natural gas and NGLs;



•

demand for oil, natural gas and NGLs;



•

levels of reserves;



•

geological considerations;



•

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and



•

the availability of drilling rigs and other costs of production and equipment.

        Fluctuations in energy prices can also greatly affect the development of new oil and natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas, or LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Recent declines in natural gas prices have had a negative impact on exploration, development and production activity and, if sustained, could lead to further decreases in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

        In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate

24

---

generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.

        Many of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experience a reduction in throughput, which would result in a decline in our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

        Because of these and other factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

If our customers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.

        If we are not successful in attracting new customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from our existing customers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements, our customers are not obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in January 2012, Chesapeake announced its intent to decrease drilling activity in predominantly dry gas areas such as the Barnett Shale region and to reduce its total dry gas production by up to 500 MMcf/d. Similarly, in February 2012, Encana announced its intent to reduce its dry gas production to approximately 3.1 Bcf/d, a decrease of approximately 250 MMcf/d from 2011 levels. For the three months ended March 31, 2012, average daily throughput on the DFW Midstream system declined approximately 17.5% compared to the three months ended December 31, 2011, primarily as a result of Chesapeake's publicly announced reduction in production. Encana's public announcement has not impacted the volume on our Grand River system but may do so in the future. Any further reductions by Chesapeake or our other customers in our areas of operation could result in further reductions in throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

Our gas gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

        Our gas gathering agreements were designed to generate stable cash flows to us over the long term. The primary mechanism on which we rely to generate our stable cash flows is an annual minimum volume commitment, or MVC, from our customers. Under these annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, the majority of our gas gathering agreements also include an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering system (or an equivalent monetary amount) over the MVC term. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period,

25

---

multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable). As of March 31, 2012, we recorded an aggregate of $3.2 million of deferred revenue, of which $1.8 million is included in accounts receivable as of March 31, 2012, with respect to shortfall payments that could reduce gathering fees received in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.



•

To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped excess natural gas on our DFW Midstream system relative to its MVC. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.



•

To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in future periods, subject to expiration in the event that there is no shortfall in subsequent periods. In such a situation, we would receive lower gathering fees in a particular contract year than we would otherwise be entitled to receive under the customer's MVC.

        Under certain circumstances, some or all of these provisions can apply in combination with one another. It is possible that the combined effect of these mechanisms could result in our receiving no revenues or cash flows from one or more customers in periods where those customers are shipping volumes on our systems. In this circumstance, we would incur compression and other operating expenses with no corresponding revenues, which would exacerbate the effect of these provisions on our results of operations. In the most extreme circumstances we could:

•

incur operating expenses with no corresponding revenues from one or more significant customers for a period of up to 35 months; or



•

all or a substantial portion of our customers could cease shipping throughput volumes at a time when their respective aggregate MVCs have been satisfied with previous throughput volume shipments.

If either of these circumstances were to occur, it would have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make distributions to our unitholders.

26

---

We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

        We do not have and we do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of natural gas reserves connected to our systems, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs.

        Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

        We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our AMIs, non-customer producers that lease acreage within one of our AMIs and produce natural gas may choose to use one of our competitors to gather that natural gas.

        In addition, our customers may develop their own gathering systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

        We gather the natural gas on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain AMIs from new customers in the future, and we may be unable to renew existing AMIs with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

•

the level of existing and new competition to provide gathering services to our markets;



•

the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;



•

the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

27

---

•

the extent to which the customers in our markets are willing to contract on a long-term basis; and



•

the effects of federal, state or local regulations on the contracting practices of our customers.

        To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operating results.

        Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our counterparties will perform or adhere to existing or future contractual arrangements.

        The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.

        Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.

        Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash flow and our ability to make distributions to our unitholders could be adversely affected.

        Our natural gas gathering pipelines connect to other pipelines and midstream facilities, such as processing plants, owned and operated by unaffiliated third parties, such as Energy Transfer Partners, L.P., Enterprise Products Partners L.P. and others. For example, all of the volumes we currently gather on the Grand River system are delivered to Enterprise Products Partners L.P.'s processing plant in Meeker, Colorado. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, or if the volumes we gather do not meet the natural gas quality

28

---

requirements of such pipelines or facilities, our revenue, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

We have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and operating results.

        We purchased the substantial majority of our initial assets from Energy Future Holdings and Chesapeake in September 2009 and from Encana in October 2011. The initial members of our executive management team were hired shortly before our initial purchase from Energy Future Holdings and, consequently, have a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management team may be unaware of and that may have a material adverse effect on our business and results of operations. The steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time to connect additional wells and maintain throughput volume. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

A shortage of skilled labor in the midstream natural gas industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.

        The gathering of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner's employees, our results of operations could be materially and adversely affected.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

        Our operations are subject to all of the risks and hazards inherent in the gathering, compressing and dehydrating of natural gas, including:

•

damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;



•

inadvertent damage from construction, vehicles, farm and utility equipment;



•

leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;



•

ruptures, fires and explosions; and



•

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

        These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks.

29

---

These risks may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive minimum volume commitments to customers during times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.

        Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover for potential environmental liabilities.

None of the proceeds of this offering will be used to maintain or grow our asset base.

        None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to pay future distributions at the then-current level. The net proceeds of the offering will be used to repay amounts outstanding under our amended and restated revolving credit facility and to make a cash distribution to Summit Investments to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us.

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

        Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

30

---

        If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, (iii) outbid by competitors, or (iv) we are unable to obtain necessary governmental or third-party consents or for any other reason, then our future growth and ability to increase cash distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

        Any acquisition involves potential risks, including, among other things:

•

mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;



•

an inability to secure adequate customer commitments to use the acquired systems or facilities;



•

the risk that natural gas or crude oil reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;



•

an inability to integrate successfully the assets or businesses we acquire;



•

coordinating geographically disparate organizations, systems and facilities;



•

the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;



•

mistaken assumptions about the overall costs of equity or debt;



•

the diversion of management's and employees' attention from other business concerns;



•

unforeseen difficulties operating in new geographic areas and business lines; and



•

customer or key employee losses at the acquired businesses.

        If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

        One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

        For instance, as we develop our medium pressure system to serve the Niobrara Shale formation, the construction will occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in

31

---

that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

        In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way or federal and state environmental or other authorizations. The approval process for gathering activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such rights-of-way or other authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be adversely affected.

We require access to significant amounts of additional capital to implement our growth strategy, as well as to meet potential future capital requirements under certain of our gas gathering agreements. Tightened capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

        In order to expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We expect to make substantial expansion capital expenditures during the twelve months ending June 30, 2013. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gas gathering agreements may also require us to spend significant amounts of capital, including over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital we would be required to spend to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our amended and restated credit facility.

        We will be required to use cash from operations or incur borrowings or sell additional common units or other securities in order to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. If we are unable to raise expansion capital, we may lose the opportunity to make acquisitions or to gather natural gas production from new upstream projects developed by our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

32

---

        We do not have any commitment from our sponsors or their affiliates, including Energy Capital Partners and GE Energy Financial Services, to provide any direct or indirect financial assistance to us following the closing of this offering.

Because our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

        Interest rates are generally at or near historic lows and may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

        Upon the closing of this offering, we expect to have approximately $     million of total indebtedness and $     million available for future borrowings under our amended and restated revolving credit facility. Our future level of debt could have important consequences to us, including the following:

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;



•

our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;



•

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and



•

our flexibility in responding to changing business and economic conditions may be limited.

        Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our amended and restated revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

        Our amended and restated revolving credit facility limits our ability to, among other things:

•

incur or guarantee additional debt;



•

make distributions on or redeem or repurchase units;

33

---

•

make certain investments and acquisitions;



•

make capital expenditures;



•

incur certain liens or permit them to exist;



•

enter into certain types of transactions with affiliates;



•

merge or consolidate with another company; and



•

transfer, sell or otherwise dispose of assets.

        Our amended and restated revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for additional information.

        The provisions of our amended and restated revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our amended and restated revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

A portion of our revenues are exposed to changes in oil and natural gas prices, and our exposure may increase in the future.

        For the year ended December 31, 2011 and the three months ended March 31, 2012, we generated approximately 80% and 86%, respectively, of our revenues pursuant to long-term, fee-based gas gathering agreements under which we are paid based on the volumes of natural gas that we gather rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited exposure to direct commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. For example, in the future we may enter into percent-of-proceeds contracts with our customers, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of natural gas and NGLs.

        Substantially all of our remaining revenue is derived from (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with our electric-drive compression and (ii) the sale of condensate volumes that we collect on the Grand River system. Our revenues with respect to our sale of retained natural gas are tied to the price of natural gas. In addition, changes in the price of oil could directly affect the revenues we receive fom the sale of condensate.

        Furthermore, we may acquire or develop additional midstream assets in the future, including assets related to commodities other than natural gas, that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.

34

---

A change in laws and regulations applicable to our assets or services may cause our operating and maintenance expenses to increase or revenue to decline.

        Various aspects of our operations are subject to extensive and frequently changing regulation as the activities of the natural gas industry often are reviewed by legislators and regulators. More stringent legislation or regulation or taxation of natural gas drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. Numerous federal, state and local departments and agencies are authorized by statute to issue, and have issued, rules and regulations binding upon participants in the natural gas industry. Our operations and the markets in which we participate are affected by these laws and regulations and may be affected by changes to such laws and regulations, which may cause us to incur materially increased operating costs or realize materially lower revenues or both.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

        A portion of our customers' natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers. In addition, the federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected to be available between late 2012 and 2014. On May 4, 2012, the Department of the Interior's Bureau of Land Management ("BLM") issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans. Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. The chemical ingredient information for hydraulic fracturing fluid is generally available to the public through online databases, and this may bring more public scrutiny to hydraulic fracturing operations. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations.

We are subject to federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements, and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

        We believe that our pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of the Federal Energy Regulatory Commission, also known as FERC, under the Natural Gas Act of 1938, also known as the NGA, and the Natural Gas Policy Act of 1978, also known as the NGPA. We are, however, subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, also known as EPAct 2005, and to FERC's regulations thereunder,

35

---

which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, the Federal Trade Commission, also known as FTC, holds statutory authority under the Energy Independence and Security Act of 2007, also known as the EISA, to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. FTC is also authorized to seek fines of up to one million dollars ($1,000,000) per day per violation. The Commodity Futures Trading Commission, also known as the CFTC, is directed under the Commodity Exchange Act, also known as the CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, also known as the Dodd-Frank Act, and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for each violation of the anti-market manipulation sections of the CEA.

        The distinction between federally-unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

        State and municipal regulations also affect our business. We are subject to state and local regulation regarding the construction and operation of our gathering systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of gas we may gather. Ratable take statutes and regulations generally require gatherers to take natural gas production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather. Many states have adopted complaint-based regulation of gathering activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances, and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering, including state regulation of production rates, maximum daily production allowable from gas wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs, and revenues.

We are subject to stringent laws and regulations that may expose us to significant costs and liabilities.

        Our natural gas gathering, compression and dehydrating operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Examples of these laws include:

•

the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;



•

the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously

36

---

owned or operated by us or at locations to which our wastes are or have been transported for disposal;

•

the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;



•

the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;



•

the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;



•

the Endangered Species Act, also known as the ESA; and



•

the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

        These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

        There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read "Business—Environmental Matters" for more information.

37

---

We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.

        The U.S. Department of Transportation, also known as DOT, through its Pipeline and Hazardous Materials Safety Administration, also known as PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in "high consequence areas," which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

Our pipelines have become subject to increased penalties and may become subject to more stringent safety regulation.

        Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and extend the integrity management requirements to certain gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

        In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending

38

---

on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that our sources, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. Depending on the particular program, we may be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

        Independent of Congress, the EPA has begun to adopt federal-level regulations controlling GHG emissions under its existing Clean Air Act authority. In 2009, the EPA issued required findings under the Clean Air Act concluding that emissions of GHGs present an endangerment to human health and the environment , and issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in September 2012. We are required to report our GHG emissions for certain of our assets. On May 12, 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

        Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

        In July 2010 Congress enacted the Dodd-Frank Act. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through regulation, primarily through rules to be adopted by the CFTC. The Dodd-Frank Act provisions are intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that may impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements.

        We currently receive a fuel retainage fee from certain of our customers that is paid in-kind to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. We

39

---

currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to hedge our exposure to fluctuations in the price of natural gas with respect to those volumes. The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

        Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

        We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiated rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

        Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

40

---

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

        Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley, which we refer to as Section 404.

        Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

        Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the fiscal year ending December 31, 2013. In addition, pursuant to the recently enacted JOBS Act, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until the later of the year following our first annual report required to be filed with the SEC or the date we are no longer an "emerging growth company," which may be up to five full fiscal years following this offering.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

        The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Risks Inherent in an Investment in Us

Summit Investments owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations and limited duties to us and our unitholders. Summit Investments and our general partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other common unitholders.

        Following this offering, Summit Investments will control our general partner, and appoint all of the officers and directors of our general partner, some of whom will also be officers, directors or principals

41

---

of Energy Capital Partners and GE Energy Financial Services, the entities that own and control Summit Investments. Although our general partner has a duty to manage us in a manner that is in our best interests, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, Summit Investments. Conflicts of interest will arise between Summit Investments, its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Summit Investments and its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

•

Neither our partnership agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift the focus of its investment and growth to areas not served by our assets.



•

Summit Investments is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.



•

Our general partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest.



•

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our general partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.



•

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.



•

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.



•

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.



•

Our general partner determines which costs incurred by it are reimbursable by us.



•

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.



•

Our partnership agreement permits us to classify up to $             million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.

42

---

•

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.



•

Our general partner intends to limit its liability regarding our contractual and other obligations.



•

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.



•

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.



•

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.



•

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Please read "Conflicts of Interest and Duties."

Our sponsors are not limited in their ability to compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

        Energy Capital Partners and GE Energy Financial Services have significantly greater resources than us and have experience making investments in midstream energy businesses. Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own interests in entities that compete with us. Energy Capital Partners and GE Energy Financial Services are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. For example, GE Energy Financial Services owns an interest in another publicly traded midstream master limited partnership. In addition, in the future, Energy Capital Partners or GE Energy Financial Services may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Energy Capital Partners or GE Energy Financial Services may offer us the opportunity to buy additional assets, neither of them are under any contractual obligation to do so and we are unable to predict whether or when such opportunities may arise.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its officers and directors or any of its affiliates, including our sponsors and their respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Duties."

43

---

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

        Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters' option to purchase additional common units. In addition, affiliates of our general partner will own            common and            subordinated units, representing an aggregate        % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

        The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•

our quarterly distributions;



•

our quarterly or annual earnings or those of other companies in our industry;



•

the loss of a large customer;



•

announcements by us or our competitors of significant contracts or acquisitions;



•

changes in accounting standards, policies, guidance, interpretations or principles;



•

general economic conditions;



•

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;



•

future sales of our common units; and



•

other factors described in these "Risk Factors."

Our partnership agreement replaces our general partner's fiduciary duties to holders of our common and subordinated units with contractual standards governing its duties.

        Our partnership agreement contains provisions that eliminate fiduciary duties to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•

how to allocate corporate opportunities among us and its affiliates;



•

whether to exercise its limited call right;



•

whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;



•

how to exercise its voting rights with respect to the units it owns;

44

---

•

whether to exercise its registration rights;



•

whether to elect to reset target distribution levels;



•

whether to transfer the incentive distribution rights or any units it owns to a third party; and



•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

        By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of our General Partner."

Our partnership agreement limits the liabilities of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that limit the liability of our general partner and the rights of our unitholders with respect to actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;



•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;



•

our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and



•

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:



•

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;



•

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

45

---

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties."

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

        In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

        While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our general partner) after the subordination period has ended. At the closing of this offering, affiliates of our general partner will

46

---

own, directly or indirectly, approximately        % of the outstanding common units and all of our outstanding subordinated units. Please read "The Partnership Agreement—Amendment of Our Partnership Agreement."

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

        Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Summit Investments, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, which we project to be approximately $19.5 million for the twelve months ending June 30, 2013. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Our Cash Distribution Policy and Restrictions on Distributions."

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner's board or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        In the event of a reset of target distribution levels, our general partner will be entitled to receive the number of common units equal to that number of common units that would have entitled it to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current

47

---

business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Summit Investments. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

        The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, affiliates of our general partner will own        % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

48

---

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Summit Investments to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote or consent of the unitholders.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer the incentive distribution rights it owns to a third party at any time without the consent of our unitholders. If our general partner transfers the incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our business and increase quarterly distributions to unitholders over time as it would if it had retained ownership of the incentive distribution rights. For example, a transfer of the incentive distribution rights by our general partner could reduce the likelihood of Summit Investments selling or contributing additional midstream assets to us, as Summit Investments would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

You will experience immediate and substantial dilution in net tangible book value of $            per common unit.

        The estimated initial public offering price of $            per common unit exceeds our net tangible book value of $             per unit. Based on the estimated initial public offering price of $            per common unit, you will incur immediate and substantial dilution of $            per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."

We may issue additional units without your approval, which would dilute your existing ownership interests.

        Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our existing unitholders' proportionate ownership interest in us will decrease;



•

the amount of cash available for distribution on each unit may decrease;



•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;



•

because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;



•

the ratio of taxable income to distributions may increase;

49

---

•

the relative voting strength of each previously outstanding unit may be diminished; and



•

the market price of the common units may decline.

Summit Investments may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

        After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, Summit Investments will hold an aggregate of                        common units and                        subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. In addition, we have agreed to provide Summit Investments with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, Summit Investments will own approximately        % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Summit Investments will own approximately        % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

•

we were conducting business in a state but had not complied with that particular state's partnership statute; or



•

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

        For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

50

---

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

        Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

        We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management."

We will incur increased costs as a result of being a publicly traded partnership.

        We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

        We have included $2.5 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

51

---

Tax Risks

        In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

        Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

        Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation

52

---

at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read "—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

        Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

        If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

        Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example,

53

---

virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election."

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations and, although the U.S. Treasury Department issued proposed regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our

54

---

unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and would result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination."

55

---

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Texas and Colorado. Colorado currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

56

---

USE OF PROCEEDS

        We expect to receive net proceeds of approximately $             million, after deducting underwriting discounts, commissions and a structuring fee, but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. Our estimates assume an initial public offering price of $            per common unit. We will use the net proceeds from this offering to:

•

repay $             million outstanding under our revolving credit facility;



•

make a cash distribution to Summit Investments of $             million in order to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us; and



•

pay estimated offering expenses of $             million.

        We intend to retain the remainder of the net proceeds for general partnership purposes.

        As of July 16, 2012, we had $352.0 million of indebtedness outstanding under our revolving credit facility, with a weighted average interest rate of 2.75%. The revolving credit facility matures on May 26, 2016, and borrowings bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. Borrowings made under our revolving credit facility within the last twelve months were used primarily to make distributions to our sponsors and fund capital expenditures.

        If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments the number of common units issued upon such exercise.

        The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Affiliates of certain of the underwriters are lenders under our revolving credit facility and will, in that respect, receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our revolving credit facility. Please read "Underwriting."

        An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, commissions and a structuring fee, to increase or decrease, respectively, by $             million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $            per common unit, would increase net proceeds to us from this offering by approximately $             million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $            per common unit, would decrease the net proceeds to us from this offering by approximately $             million. To the extent there is an increase or decrease in the net proceeds we receive from this offering, we will make a corresponding increase or decrease in the cash distribution to Summit Investments.

57

---

CAPITALIZATION

        The following table shows:

•

Summit Midstream Predecessor's historical cash and cash equivalents and capitalization, as of March 31, 2012; and



•

our as adjusted cash and cash equivalents and capitalization, as of March 31, 2012, giving effect to:



•

our receipt and use of net proceeds of $             million from the issuance and sale of                         common units to the public at an assumed initial offering price of $            per unit in the manner described in "Use of Proceeds"; and



•

the other transactions described in "Summary—Formation Transactions and Partnership Structure."

        We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations." This table assumes that the underwriters' option to purchase additional common units is not exercised.

58

---

DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2012, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters' option to purchase additional common units is not exercised, our net tangible book value was $             million, or $            per unit. Net tangible book value excludes $             million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

        The following table sets forth the number of units that we will issue and the total consideration to be contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:

59

---

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading "—Assumptions and Considerations" below. In addition, please read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical financial statements, and the notes thereto, included elsewhere in this prospectus.

General

        Our Cash Distribution Policy.    Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement. To that end, our partnership agreement requires us to distribute all of our available cash quarterly. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

        Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.    There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to the extent we have available cash as defined in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

•

Our cash distribution policy will be subject to restrictions on distributions under our revolving credit facility or other debt agreements entered into in the future. Our revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility."



•

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.



•

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Summit Investments) after the subordination period has ended. At the closing of this offering, Summit Investments will own our general partner as well as approximately        % of our outstanding common units and all of our subordinated units, representing an aggregate         % limited partner interest in us.

60

---

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.



•

Under Section 17-607 of the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.



•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash."



•

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate in order to service or repay our debt or fund expansion capital expenditures.

        All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $             million cash basket, that represent non-operating sources of cash. Consequently, it is possible that distributions from operating surplus may represent a return of capital. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.

        Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital.    Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions, expansion capital expenditures or otherwise, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no restrictions in our partnership agreement or our amended and restated revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional bank borrowings (under our amended and restated revolving credit facility or otherwise) or other debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

        Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $            per unit per complete quarter, or $            per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter

61

---

ending                     , 2012. This equates to an aggregate cash distribution of approximately $             million per quarter, or approximately $             million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding immediately after the completion of this offering. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to this policy will be subject to the factors described above under the caption "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

        If and to the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from Summit Investments a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds before expenses but after deducting underwriting discounts, commissions and structuring fees. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

        The table below sets forth the number of common and subordinated units to be outstanding upon the closing of this offering and the number of unit equivalents represented by the 2.0% general partner interest and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $            per unit per quarter ($            per unit on an annualized basis).

        The subordination period generally will end if we have earned and paid at least $            on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after                        , 2015. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $            (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest and the related distribution on the incentive distribution rights for any four consecutive quarter period ending on or after                        , 2013. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common

62

---

units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through September 30, 2012 based on the actual length of the period.

        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $            per unit for the twelve months ending June 30, 2013. In those sections, we present two tables, consisting of:

•

"Partnership Unaudited Historical As Adjusted Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution on a historical as adjusted basis for the year ended December 31, 2011 and the twelve months ended March 31, 2012, derived from our historical consolidated financial statements that are included in this prospectus, as adjusted to give effect to the incremental general and administrative expenses associated with being a publicly traded partnership and our estimate of the amount of our historical maintenance capital expenditures; and



•

"Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013," in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2013.

Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the twelve months ended March 31, 2012

        We acquired the Grand River system from Encana in October 2011 and, therefore, our historical consolidated financial statements that are included in this prospectus do not reflect a full year of financial results of the Grand River system. If we had completed our initial public offering and the related transactions contemplated by this prospectus on January 1, 2011, our historical as adjusted cash available for distribution for the year ended December 31, 2011, which includes two months of operations attributable to the Grand River system, would have been approximately $39.8 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of the common units but only a cash distribution of $            per unit per quarter ($            per unit on an annualized basis), or approximately        % of the minimum quarterly distribution, on our subordinated units for such period.

        If we had completed our initial public offering and the related transactions contemplated by this prospectus on April 1, 2011, our historical as adjusted cash available for distribution for the twelve months ended March 31, 2012, which includes five months of operations attributable to the Grand River system, would have been approximately $49.3 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of the common units but only a cash distribution of $            per unit per quarter ($            per unit on an annualized basis), or approximately        % of the minimum quarterly distribution, on our subordinated units for such period.

63

---

        Unaudited historical as adjusted cash available for distribution for the year ended December 31, 2011 and the twelve months ended March 31, 2012 includes incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. These expenses are not reflected in the historical consolidated financial statements of our Predecessor. Our estimate of incremental general and administrative expenses is based upon currently available information.

        The adjusted amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed on January 1, 2011 or April 1, 2011. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on January 1, 2011 or April 1, 2011.

        The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2011 and the twelve months ended March 31, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related transactions contemplated by this prospectus had been consummated on January 1, 2011 or April 1, 2011. Each of the adjustments presented below is explained in the footnotes to such adjustments.

64

---

Partnership Unaudited Historical As Adjusted Cash Available for Distribution

65

---

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2013

        We forecast that our estimated cash available for distribution for the twelve months ending June 30, 2013 will be approximately $85.9 million. This amount would exceed by $             million the amount needed to pay the total annualized minimum quarterly distribution of $            on all of our units for the twelve months ending June 30, 2013.

66

---

        We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements in support of our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013. This forecast is a forward-looking statement and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions on which we base our belief that we will generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

        The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The reports of our independent registered public accounting firm included in this prospectus relate to our and our Predecessor's historical financial information, and those reports do not extend to the prospective financial information and should not be read to do so.

        When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013.

        We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement our historical consolidated financial statements included elsewhere in this prospectus in support of our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders and the corresponding distributions on our general partner's 2.0% interest for the twelve months ending June 30, 2013. Please read below under "—Assumptions and Considerations" for further information as to the assumptions we have made for the financial forecast.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution to all of our unitholders for the twelve months ending June 30, 2013, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

67

---

Estimated Cash Available for Distribution

68

---

Assumptions and Considerations

        Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate sufficient cash available for distribution to pay the total annualized minimum quarterly distribution to all unitholders for the twelve months ending June 30, 2013.

General Considerations

        As discussed further below, a significant portion of the increase in cash available for distribution for the twelve months ending June 30, 2013 as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 is attributable to additional revenues that we expect to generate under gas gathering agreements related to our Grand River system. Because we acquired the Grand River system in October 2011, revenues from these gas gathering agreements are not included in our historical results prior to November 2011.

Revenue

        We estimate that we will generate revenue of $152.9 million for the twelve months ending June 30, 2013, compared to $103.6 million for the year ended December 31, 2011 and $120.2 million for the twelve months ended March 31, 2012. The significant increase in revenue for the forecast period as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 is primarily attributable to the inclusion of our Grand River system for the entire forecast period as compared to just two months for the year ended December 31, 2011 and just five months for the twelve months ended March 31, 2012. Approximately 44% of our projected revenue is expected to be

69

---

generated from our Grand River system and approximately 56% is expected to be generated from our DFW Midstream system for the twelve month period ending June 30, 2013. Approximately 87% of our revenue is associated with fee-based gathering services that we provide to our customers. Approximately 8% of our revenue is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collect on our Grand River system. We generate the remainder of our revenue by charging certain customers with respect to costs we incur on their behalf to deliver pipeline quality natural gas to third-party pipelines and costs we incur to operate electric-drive compression on the Grand River system.

•

Volumes.  We estimate that we will gather an average of 914 MMcf/d for the twelve months ending June 30, 2013. This compares to our average daily throughput in the first quarter of 2012 of approximately 908 MMcf/d and an average of 428 MMcf/d for the year ended December 31, 2011 and 584 MMcf/d for the twelve months ended March 31, 2012. This expected increase in volumes in the forecast period as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 is primarily due to our acquisition of the Grand River system in October 2011 and is partially offset by natural declines in production from existing wells on both of our gathering systems.



•

Grand River volumes. Our average daily throughput on the Grand River system in the first quarter of 2012 was approximately 593 MMcf/d. We expect throughput will average approximately 572 MMcf/d for the twelve months ending June 30, 2013, primarily based on (i) production schedules provided by certain of our customers and (ii) our assumption that our other customers will drill and connect new wells to offset the natural decline of existing wells connected to the Grand River system, thereby keeping throughput in the forecast period relatively flat with current throughput. Projected throughput for the twelve months ending June 30, 2013 compares to aggregate minimum volume commitments of 470 MMcf/d from our Grand River customers over the same time period and average daily throughput of 596 MMcf/d for the two months ended December 31, 2011 and 595 MMcf/d for the five months ended March 31, 2012.



•

DFW Midstream volumes. Our average daily throughput on the DFW Midstream system in the first quarter of 2012 was approximately 315 MMcf/d. We expect throughput on the DFW Midstream system will average approximately 342 MMcf/d for the twelve months ending June 30, 2013, primarily based on our assumption that in the aggregate, our customers' production will be more than sufficient to offset the natural decline of existing wells connected to the DFW Midstream system. Projected throughput for the twelve months ending June 30, 2013 compares to aggregate minimum volume commitments of 182 MMcf/d from our DFW Midstream customers over the same time period and average throughput of 329 MMcf/d for the year ended December 31, 2011 and 337 MMcf/d for the twelve months ended March 31, 2012.



•

Fees.  We estimate that we will receive an average gathering fee of $0.40 per Mcf for the twelve months ending June 30, 2013, compared to $0.53 per Mcf for the year ended December 31, 2011 and $0.46 per Mcf for the twelve months ended March 31, 2012. Our calculation of the average gathering fee is based on an analysis of the projected volumes and fixed contractual fees (subject to contractual escalation in certain cases) under each of our gas gathering agreements. We expect our overall average gathering fee to be lower in the forecast period as compared to the year ended December 31, 2011 and the twelve months ended March 31, 2012 primarily as a result of the inclusion of our Grand River system, which generates a lower average gathering fee per Mcf than our DFW Midstream system, in the forecast period. All of our gathering fees are fixed and subject to the terms of the gas gathering agreements we have with each of our customers.

70

---

•

Grand River Fees. Our average gathering fees on the Grand River system for the year ended December 31, 2011 and the twelve months ended March 31, 2012 were $0.30 per Mcf and $0.28 per Mcf, respectively. We estimate that we will receive an average gathering fee on the Grand River system of $0.28 per Mcf for the twelve months ending June 30, 2013.



•

DFW Midstream Fees. Our average gathering fees on the DFW Midstream system for the year ended December 31, 2011 and the twelve months ended March 31, 2012 were $0.60 per Mcf and $0.59 per Mcf, respectively. We estimate that we will receive an average gathering fee on the DFW Midstream system of $0.60 per Mcf for the twelve months ending June 30, 2013.



•

Natural Gas and Condensate Sales.  Approximately 8% of our projected revenue in the twelve months ending June 30, 2013 is associated with (i) the sale of physical natural gas that we retain from our DFW Midstream customers to offset our power expense and (ii) the sale of condensate volumes that we collect on our Grand River system. This projection is based on our assumption that we will sell the retained natural gas at Henry Hub pricing as of June 26, 2012, less a basis differential consistent with historical differentials, less contracted transportation costs, and that we will sell the condensate at the NYMEX crude oil strip price as of June 26, 2012, less a basis differential consistent with historical differentials. Fuel retainage volumes are projected according to specific terms embedded within all of the gas gathering agreements for our DFW Midstream customers. We assume that we will sell 8.6 MMBtu/d of natural gas at $3.07 per MMBtu for the twelve months ending June 30, 2013, compared to 10.8 MMBtu/d of natural gas at $3.60 per MMBtu for the year ended December 31, 2011 and 9.5 MMBtu/d of natural gas at $3.24 per MMBtu for the twelve months ended March 31, 2012. Condensate volumes are projected according to historical condensate yields based primarily on projected throughput on our Mamm Creek and South Parachute gathering assets. We assume that we will sell 112 Bbls/d of condensate at $70 per Bbl for the twelve months ending June 30, 2013, compared to 20 Bbls/d of condensate at $85 per Bbl for the year ended December 31, 2011 and 60 Bbls/d of condensate at $88 per Bbl for the twelve months ended March 31, 2012.



•

Sensitivity Analysis.  The actual volume of natural gas that we gather on our systems will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2013 is above or below our forecast. If the actual volume of natural gas we gather on our systems is below our forecast, we may not have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the forecast period. If the actual volume of natural gas we gather on our systems for the twelve months ending June 30, 2013 was 10% lower than our forecast, we would have sufficient cash available to pay the full distribution to holders of our common units and only        % of the aggregate annualized minimum quarterly distribution to the holders of our subordinated units.

Operating and Maintenance Expenses

        Our primary operating and maintenance expenses include labor costs, compression costs, ad valorem and property taxes, utilities and contract services. We estimate that we will incur operating and maintenance expenses of $49.4 million for the twelve months ending June 30, 2013, compared to operating and maintenance expenses of $29.9 million for the year ended December 31, 2011 and $34.7 million for the twelve months ended March 31, 2012. Included in these amounts is compression expense that we incur to operate our electric-drive compression assets on our DFW Midstream system, which varies with (i) our power consumption, which is correlated to the actual throughput on our DFW Midstream system, and (ii) the cost of power. We estimate that we will incur compression costs of $12.2 million, or $0.10 per Mcf, for the twelve months ending June 30, 2013, compared to compression costs of $13.4 million, or $0.11 per Mcf, for the year ended December 31, 2011 and $13.1 million, or $0.11 per Mcf, for the twelve months ended March 31, 2012. Under our gas gathering agreements with

71

---

our DFW Midstream customers, we physically retain a certain percentage of each customer's throughput that we then sell to offset the power costs we incur. Under our gas gathering agreements with our Grand River customers, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets. Excluding our total compression costs, we estimate that we will incur operating and maintenance expenses of $37.1 million, or $0.11 per Mcf, for the twelve months ending June 30, 2013, compared to operating and maintenance expenses of $16.5 million, or $0.11 per Mcf, for the year ended December 31, 2011 and $21.6 million, or $0.10 per Mcf, for the twelve months ended March 31, 2012. Increased aggregate operating and maintenance expenses for the twelve months ending June 30, 2013 are primarily related to the acquisition of the Grand River system in October 2011 and the additional DFW Midstream operations personnel that were hired during the year ended December 31, 2011 and the twelve months ended March 31, 2012.

        We expect that operating and maintenance expenses will increase in the aggregate, primarily as a result of higher compression expenses, as throughput increases across our gathering systems. However, we expect operating and maintenance expenses net of compression costs on a dollar per Mcf basis to decline as throughput on our systems increases at a higher rate than our non-compression operating and maintenance expenses and our compression costs are passed on to our customers or offset by our sale of physical natural gas that we retain from our DFW Midstream customers, as applicable.

General and Administrative Expenses

        Our general and administrative expenses will primarily consist of general and administrative expenses that we incur and payments that we make to our general partner in exchange for the provision of general and administrative services, including approximately $2.5 million of expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs and director compensation.

        We expect our general and administrative expenses to total approximately $21.0 million for the twelve months ending June 30, 2013, compared to general and administrative expenses of $17.5 million for the year ended December 31, 2011 and $18.0 million for the twelve months ended March 31, 2012. The primary drivers of our anticipated increase in general and administrative expenses are our acquisition of the Grand River system in October 2011 including the associated expense of hiring our Grand River asset management and other corporate personnel, and $2.5 million of incremental expenses related to being a publicly traded partnership, partially offset by an approximately $1.6 million reduction in non-cash compensation expenses. Non-cash compensation expense totaled $3.4 million in the twelve months ended December 31, 2011 and included two one-time adjustments totaling $2.4 million, approximately $1.4 million of which was associated with a modification to the DFW Midstream Class B rate of return payout hurdle and approximately $1.0 million of which was associated with non-cash compensation expense for years prior to 2011. As a result, the $1.8 million of non-cash compensation expense projected for the twelve months ending June 30, 2013 is higher than the $1.0 million of normalized 2011 non-cash compensation expense in the twelve months ended December 31, 2011 due to compensatory awards issued in April 2011, October 2011, and January 2012.

Depreciation and Amortization Expense

        We estimate that depreciation and amortization expense for the twelve months ending June 30, 2013 will be $32.9 million, compared to $11.9 million for the year ended December 31, 2011 and $18.6 million for the twelve months ended March 31, 2012. Estimated depreciation and amortization

72

---

expense reflects management's estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization expense is primarily attributable to the inclusion of a full year of depreciation on our Grand River assets and expected capital investments on both the DFW Midstream system and the Grand River system.

Capital Expenditures

        We estimate that total capital expenditures for the twelve months ending June 30, 2013 will be $64.5 million, compared to $667.7 million for the year ended December 31, 2011 and $668.7 million for the twelve months ended March 31, 2012. Approximately $590.0 million of our capital expenditures for the year ended December 31, 2011 and the twelve months ended March 31, 2012 were related to the acquisition of the Grand River system in October 2011. Capital expenditures attributable to the DFW Midstream system and Grand River system in November and December 2011 accounted for the remainder. Substantially all of our projected capital expenditures are associated with expanding our existing Grand River and DFW Midstream systems. We estimate that total capital expenditures on our Grand River system will be approximately $30.7 million for the twelve months ending June 30, 2013, which will account for approximately 48% of our total capital expenditures during the forecast period, with the DFW Midstream system accounting for the remainder.

•

Maintenance Capital Expenditures.  Historically, we did not make a distinction between maintenance and expansion capital expenditures. We estimate that we will spend $5.2 million for maintenance capital expenditures for the twelve months ending June 30, 2013. The types of maintenance capital expenditures that we expect to incur include expenditures to connect additional pad sites to maintain current volumes and expenditures to replace system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives. It has been customary in the regions in which we operate for producers to bear the cost of connecting individual wells to our pad site meters or central receipt points. In areas where multiple wells are located on a single pad site, such as on the DFW Midstream system, individual wells are connected to our measurement meter on the pad site, which is in turn connected to our gathering pipeline system. In other areas without multiple well pad sites, such as parts of the Grand River system, individual wells are connected to our nearest central receipt point meter, which in turn is connected to our pipeline gathering system.



•

Expansion Capital Expenditures.  We estimate that our expansion capital expenditures for the twelve months ending June 30, 2013 will total $59.3 million, of which approximately $28.2 million are attributable to the Grand River system and approximately $31.0 million are attributable to the DFW Midstream system. Although we expect that these expenditures will increase throughput over time, we have not assumed any additional volumes during the forecast period related to these expenditures.



•

Grand River system. The majority of our projected expansion capital expenditures on the Grand River system are associated with looping certain sections of pipeline in order to increase system capacity, optimize throughput hydraulics and operating pressures and increase our pad site connections for ongoing low-pressure Mesaverde formation drilling activities.



•

DFW Midstream system. The substantial majority of the expansion capital expenditures associated with the DFW Midstream system will be to construct new low-pressure pipeline laterals to connect additional identified pad sites for our existing customers, install additional compression assets and complete the construction of several looping pipelines on the DFW Midstream system to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures. We are also forecasting expansion capital expenditures during the twelve months ending June 30, 2013 of approximately $11.9 million

73

---

associated with five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.

Financing

•

Amended and Restated Revolving Credit Facility.  Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:



•

permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to be less than 2.50 to 1.00;



•

permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to be above 5.00 to 1.00 (or 5.50 to 1.00 if we have made certain business acquisitions);



•

incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject to customary exceptions for permitted liens;



•

make any investments, subject to customary exceptions for certain permitted investments;



•

engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactions of such types;



•

pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants under the amended and restated credit agreement;



•

enter into any swap agreements or power purchase agreements, subject to customary exceptions, such as the entry into swap agreements and power purchase agreements in the ordinary course of business; and



•

enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.

        Repayments of principal under our amended and restated credit facility are not reflected as reductions in estimated cash available for distribution.

•

Cash and Liquidity.  At the closing of this offering, we expect to have $             million of capacity under our amended and restated revolving credit facility after using a portion of the net proceeds of this offering to repay approximately $             million currently outstanding under our amended and restated revolving credit facility. Please read "Use of Proceeds." At the closing of this offering, we expect to have outstanding indebtedness of approximately $             million and a total leverage ratio of approximately 2.0x, which we believe will provide us with sufficient liquidity to fund our anticipated expansion capital expenditures during the forecast period. We intend to fund our forecasted maintenance capital expenditures with operating cash flow. We intend to refinance debt as it comes due, and because our credit facility does not require any principal payments until the facility matures in 2016, we have assumed no principal repayments during the forecast period.



•

Interest Expense.  We estimate that our interest expense excluding the effects of amortization of deferred loan costs for the twelve months ending June 30, 2013 will be approximately $7.8 million, compared to $2.5 million for the year ended December 31, 2011 and $6.5 million for the twelve months ended March 31, 2012. Our projected interest expense is based on an assumed average outstanding debt balance of $201.5 million under our amended and restated

74

---

revolving credit facility during the forecasted period, including borrowings to finance our projected expansion capital expenditures, with an assumed weighted average interest rate of        % and a commitment fee of        % that we expect to pay on the undrawn portion of the revolving credit facility. We have assumed no interest income with respect to the cash that we maintain on our balance sheet during the forecast period.

Regulatory, Industry and Economic Factors

        Our forecast for the twelve months ending June 30, 2013 is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.



•

There will not be any major adverse change in the midstream energy sector, commodity prices or in market, insurance or general economic conditions.



•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.



•

We will not make any acquisitions or other significant expansion capital expenditures (other than as described above).

75

---

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

        Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                         , 2012, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through                        , 2012 based on the actual length of the period.

Definition of Available Cash

        Available cash generally means, for any quarter, all cash on hand at the end of that quarter:

•

less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:



•

provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);



•

comply with applicable law, any of our debt instruments or other agreements; and



•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);



•

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

        The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Intent to Distribute the Minimum Quarterly Distribution

        We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $            per unit, or $            on an annualized basis, to the extent we have

76

---

sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Amended and Restated Revolving Credit Facility" for a discussion of the restrictions included in our amended and restated revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

        Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $            per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any limited partner units that it owns. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.

Operating Surplus and Capital Surplus

General

        All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

        We define operating surplus as:

•

$             million (as described below); plus



•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus



•

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus



•

cash distributions (including incremental distributions on incentive distribution rights) paid on equity issued, other than equity issued in this offering, to finance all or a portion of the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date

77

---

that we enter into a binding obligation to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of; plus

•

cash distributions (including incremental distributions on incentive distribution rights) paid on equity issued, other than equity issued in this offering, to pay the construction-period interest on debt incurred, or to pay construction-period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less



•

all of our operating expenditures (as defined below) after the closing of this offering; less



•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less



•

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less



•

any cash loss realized on disposition of an investment capital expenditure.

        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $             million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of ordinary course asset retirements or replacements, (iv) the termination of commodity hedge contracts or interest rate hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of the contract), (v) capital contributions received and (vi) corporate reorganizations or restructurings.

        We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses to our general partner and its affiliates, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), director and officer compensation, repayment of working

78

---

capital borrowings and non-pro rata repurchases of our units; provided, however, that operating expenditures will not include:

•

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);



•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;



•

expansion capital expenditures;



•

investment capital expenditures;



•

payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;



•

distributions to our partners; or



•

non-pro rata purchases of any class of our units made with the proceeds of an interim capital transaction.

Capital Surplus

        Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

•

borrowings other than working capital borrowings;



•

sales of our equity and debt securities; and



•

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

        Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

        Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our operating income or operating capacity over the long term. We expect that a primary component of maintenance capital expenditures will include expenditures to connect additional wells to our gathering systems to offset natural declines in production over time and for routine equipment and pipeline maintenance or replacement due to obsolescence. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to

79

---

occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of.

        Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Expansion capital expenditures include interest payments (and related fees) on debt incurred and issued to finance the construction of such capital improvement and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or operating income.

        Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand, our operating capacity or operating income over the long-term.

        Capital expenditures that are made in part for maintenance capital purposes, expansion capital purposes and/or investment capital purposes will be allocated as maintenance capital expenditures, expansion capital expenditures or investment capital expenditures by our general partner.

Subordination Period

General

        Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $            per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

        Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after                        , 2015, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the related distribution on the general partner interest equaled or

80

---

exceeded $            (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•

the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded (i) the sum of $            (the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during those periods on a fully diluted weighted average basis and (ii) the corresponding distribution on our 2.0% general partner interest; and



•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

        Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after                        , 2013, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the related distribution on the general partner interest equaled or exceeded $            (150.0% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;



•

the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $            (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted weighted average basis and (ii) the distributions made on our 2.0% general partner interest and the incentive distribution rights; and



•

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration of the Subordination Period

        When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately and automatically convert into one common unit;



•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and



•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

81

---

Definition of Adjusted Operating Surplus

        Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

•

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption "—Operating Surplus and Capital Surplus—Operating Surplus" above); less



•

any net increase in working capital borrowings with respect to that period; less



•

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus



•

any net decrease in working capital borrowings with respect to that period; plus



•

any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the third bullet point above; plus



•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

82

---

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

        Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

        Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

        The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

        If for any quarter:

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and



•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "first target distribution");



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "second target distribution");



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $            per unit for that quarter (the "third target distribution"); and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of

83

---

our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

        In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined

84

---

formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner's interest in us immediately prior to the reset election.

        The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

        Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;



•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;



•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

        The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels

85

---

based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $            .

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be                                    common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $             for the two quarters prior to the reset.

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be                        common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $            . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the

86

---

average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $            , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $            .

        Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

        We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and



•

thereafter, as if they were from operating surplus.

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

        Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to

87

---

convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;



•

target distribution levels;



•

the unrecovered initial unit price;



•

the number of general partner units comprising the general partner interest; and



•

the per unit arrearage in payment of the minimum quarterly distribution on the common units.

        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be split into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

        If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated

88

---

units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

        The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;



•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;



•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;



•

fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;



•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;



•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;



•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

        The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

89

---

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

•

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;



•

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and



•

thereafter, 100.0% to our general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

        Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

90

---

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

        The following table presents as of the dates and for the periods indicated the selected historical consolidated financial and operating data of our Predecessor. On September 3, 2009, we acquired a controlling interest in DFW Midstream Services LLC, which we refer to as our Initial Predecessor for the period prior to such date. We use the term Summit Midstream Predecessor to describe our Predecessor's operations after September 3, 2009. We acquired the Grand River system on October 27, 2011 and we have included its financial results in the financial statements of Summit Midstream Predecessor since the date of acquisition.

        The selected historical consolidated financial data presented as of March 31, 2012 and for the three months ended March 31, 2012 and March 31, 2011 are derived from our unaudited historical condensed financial statements included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2011 and December 31, 2010 and for the period from September 3, 2009 to December 31, 2009, for the year ended December 31, 2011 and the year ended December 31, 2010 have been derived from the audited historical consolidated financial statements of Summit Midstream Predecessor included elsewhere in this prospectus. The selected historical balance sheet data as of December 31, 2009 are derived from the audited historical financial statement of Summit Midstream Predecessor that are not included in this prospectus. The selected historical financial data for the period from January 1, 2009 to September 3, 2009 are derived from the audited historical financial statements of our Initial Predecessor included elsewhere in this prospectus. We acquired our initial assets from Energy Future Holdings Corp. and Chesapeake effective as of September 3, 2009.

        For a detailed discussion of the information presented in the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with the historical audited and unaudited consolidated financial statements and related notes of our Predecessor included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information below.

        The following table presents the non-GAAP financial measures of EBITDA and Adjusted EBITDA, which we use in our business as measures of performance and liquidity. We define EBITDA as net income:

•

Plus:



•

interest expense;



•

income tax expense; and



•

depreciation and amortization expense.



•

Less:



•

interest income; and



•

income tax benefit.

        We define Adjusted EBITDA as EBITDA:

•

Plus:



•

non-cash equity compensation; and



•

deferred revenue related to MVCs.

For a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measure" on page 93.

91

---

92

---

Non-GAAP Financial Measure

        We include in this prospectus the non-GAAP financial measures of EBITDA and Adjusted EBITDA. We provide a reconciliation of this non-GAAP financial measure to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

EBITDA

        We define EBITDA as net income (loss):

•

Plus:



•

interest expense;



•

income tax expense; and



•

depreciation and amortization expense.



•

Less:



•

interest income; and



•

income tax benefit.

        We define Adjusted EBITDA as EBITDA:

•

Plus:



•

non-cash equity compensation; and



•

deferred revenue related to MVCs.

93

---

        EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors and lenders, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;



•

the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;



•

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

        The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net cash flows provided by operating activities and net income. Our non-GAAP financial measures of EBITDA and Adjusted EBITDA should not be considered as an alternative to net income or cash flows from operating activities. You should not consider EBITDA and Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered as alternatives to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

•

certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;



•

EBITDA and Adjusted EBITDA do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;



•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital needs;



•

although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements; and



•

our computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

        Management compensates for the limitations of EBITDA and Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management's decision-making process.

94

---

        The following table presents a reconciliation of Adjusted EBITDA to net income and net cash flows provided by operating activities for each of the periods indicated:

 

---

(1)

EBITDA and Adjusted EBITDA for the three months ended March 31, 2012 and for the year ended December 31, 2011 include $0.2 million and $3.2 million, respectively, in transaction costs related to our acquisition of Grand River. EBITDA and Adjusted EBITDA for the year ended December 31, 2010 include $1.8 million in settlement expenses related to a dispute with a contractor at the DFW Midstream system. EBITDA and Adjusted EBITDA for the 2009 Summit Midstream Predecessor Period include transaction costs of $3.9 million primarily related to the acquisition of the DFW Midstream system in September 2009. These unusual and non-recurring expenses were included in the calculations of EBITDA and Adjusted EBITDA, and were settled in cash.

(2)

Interest expense presented excludes $0.6 million and $0.2 million in amortization of deferred loan costs and $2.0 million and $3.5 million in pay in kind interest on promissory notes payable to our sponsors for the year ended December 31, 2011 and for the three months ended March 31, 2012.

95

---

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

        You should read the following discussion of the financial condition and results of operations of Summit Midstream Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements and related notes of Summit Midstream Partners, LLC, which we refer to as Summit Midstream Predecessor, included elsewhere in this prospectus. We sometimes refer to DFW Midstream Services LLC, or our Initial Predecessor, and Summit Midstream Predecessor collectively as our Predecessor. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

Overview

        We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of May 31, 2012, our gathering systems had approximately 386 miles of pipeline and 147,600 horsepower of compression. During the first quarter of 2012, our systems gathered an average of approximately 908 MMcf/d of natural gas, of which approximately 62% contained natural gas liquids, or NGLs, that were extracted by a third party processor.

        We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

        Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments. Our AMIs cover approximately 330,000 acres in the aggregate, have original terms that range from 10 years to 25 years, and provide that any natural gas producing wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.6 Tcf at March 31, 2012 and, through 2020, average approximately 643 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of March 31, 2012, had a weighted average remaining life of 11.6 years assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

Our Operations

        Our results are driven primarily by the volumes of natural gas that we gather across our systems. For the year ended December 31, 2011 and the quarter ended March 31, 2012, approximately 80% and 86%, respectively, of our revenue was associated with fee-based gathering services that we provided to our customers. Approximately 12% of our revenue was associated with (i) the sale of physical natural gas that we retained from our DFW Midstream customers to offset our power expense associated with the operation of our electric-drive compression and (ii) the sale of condensate volumes that we collected on our Grand River system. We generated the remainder of our revenue by charging certain customers with respect to costs we incurred on their behalf to deliver pipeline quality natural gas to

96

---

third-party pipelines and costs we incurred to operate electric-drive compression on the Grand River system.

        We contract with producers to gather natural gas from pad sites and central receipt points connected to the Grand River system and our gathering system in the Barnett Shale, which we refer to as the DFW Midstream system. These receipt points are connected to our gathering pipelines through which we compress natural gas and deliver it to third-party processing plants or downstream pipelines for ultimate delivery to end users.

        We currently provide substantially all of our gathering services under long-term, fee-based gas gathering agreements, which limit our direct commodity price exposure, and we do not take title to the natural gas we gather on behalf of our customers. Under these agreements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather. We are party to seven, long-term gas gathering agreements with producers in the Barnett Shale and, in connection with our acquisition of the Grand River system from a subsidiary of Encana in October 2011, we entered into three, long-term gas gathering agreements with Encana and assumed six gas gathering agreements with five other producers, three of which are long-term agreements.

        These agreements provide us with a revenue stream that is not subject to direct commodity price risk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. On the Grand River system, we either (i) consume physical gas on the system to operate our gas-fired compression assets or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

        We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather. If our customers delay drilling or temporarily shut-in production due to persistently low commodity prices, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers. Please read below and "Risk Factors—Significant prolonged changes in natural gas prices could affect supply and demand, reducing throughput on our systems and adversely affecting our revenues and cash available to make distributions to you over the long-term" for additional information regarding the recent decline in natural gas prices and the impact it has had on our customers and our operations.

        We have exposure to both liquids-rich and "dry" gas regions, and we believe our gathering systems are well positioned to capture additional volumes from increased producer activity in the future. Dry gas regions contain natural gas reserves that are primarily comprised of methane, as compared to liquids-rich regions that contain NGLs in addition to methane.

        In the Piceance Basin, our Grand River system benefits from its exposure to liquids-rich gas production from the Mesaverde formation. The attractive economics associated with the production from this formation, combined with our minimum volume commitments from major producers in the area, provide us with stable cash flows and visible growth in the future. In addition, certain of our customers have joint venture agreements in place that provide for the development of portions of the Piceance Basin in our AMIs utilizing third-party funds. We believe the drilling activity from these partnerships will benefit our Grand River system. The Grand River system also serves the emerging Mancos and Niobrara formations, which we expect will become more active to the extent that natural gas prices increase.

        Our DFW Midstream system benefits from its AMIs that cover the most prolific dry gas area of the Barnett Shale. We believe that this area offers our customers a compelling opportunity to maximize drilling economics due to the high estimated ultimate recovery of natural gas per well and relatively low drilling costs when compared to other dry gas resource basins. While recent market prices for natural gas have resulted in reduced drilling activity in the Barnett Shale, there remains a significant

97

---

number of wells in various stages of completion in our AMIs that have already been connected to pad sites on the DFW Midstream system. These wells represent an opportunity to increase throughput on the DFW Midstream system at minimal incremental capital costs. In addition, because of the urban environment in which the DFW Midstream system is located, we expect that this area will continue to be developed by our customers using a high density pad site drilling strategy that is designed to support multiple wells from a single location. Instead of constructing pipelines to multiple wells, we connect to an individual pad site, some of which can accommodate up to 30 wells, and gather all of the natural gas produced at that site, thus minimizing our future capital expenditures. This pad site strategy substantially increases the efficiency of both the producers' drilling activities as well as our gathering activities and economics.

How We Evaluate Our Operations

        Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include (i) throughput volume, (ii) operations and maintenance expenses, (iii) Adjusted EBITDA and (iv) distributable cash flow. We manage our business and analyze our results of operations as a single business segment.

Throughput Volume

        The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River and DFW Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

        We must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas is impacted by:

•

successful drilling activity within our AMIs;



•

the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;



•

the number of new pad sites in our AMIs awaiting lateral connections;



•

our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and



•

our ability to gather natural gas that has been released from commitments with our competitors.

        We actively monitor producer activity in the areas served by our gathering systems to pursue new supply opportunities.

Operations and Maintenance Expenses

        We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs,

98

---

compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems, but may fluctuate depending on the activities performed during a specific period. Our compressors in the Barnett Shale are electric driven and power costs are directly correlated to the run-time of compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our Barnett Shale customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain Barnett Shale customers to deliver pipeline quality natural gas to third-party pipelines. In the Piceance Basin, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

        We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define Adjusted EBITDA as EBITDA plus non-cash equity compensation and deferred revenue related to MVCs. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure." Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures, to analyze our performance and liquidity. Distributable cash flow will not reflect changes in working capital balances.

        EBITDA, Adjusted EBITDA and distributable cash flow are used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

(EBITDA and Adjusted EBITDA)

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;



•

the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;



•

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

(Distributable Cash Flow)

•

the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and



•

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Note Regarding Non-GAAP Financial Measures

        EBITDA, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations.

99

---

Net income and net cash flows provided by operating activities are the GAAP measures most directly comparable to EBITDA, Adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider EBITDA, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

General Trends and Outlook

        Our business has been, and we expect our future business to continue to be, affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural gas supply and demand dynamics

        Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $2.42 per MMBtu as of May 31, 2012, compared to a high of $13.58 per MMBtu in July 2008. The lower price of natural gas is due in part to increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage, warm winter weather and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration ("EIA"), average annual natural gas production in the United States increased 14.1% from 55.3 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Over the same time period, natural gas consumption increased only 4.7% to 66.8 Bcf/d. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.2 Tcf as of June 3, 2011 to approximately 2.9 Tcf as of June 1, 2012 due to the unseasonably warm winter of 2011-2012 and to the decisions of many producers to store natural gas in the expectation of higher prices in the future. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,403 as of December 31, 2008 to approximately 515 as of May 31, 2012 according to Smith Bits, as a number of producers have curtailed their exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

        Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in December 2008, 50% of the electricity in the United States was generated by coal-fired power plants and in December 2011, 41% of the electricity in the United States was generated by coal-fired power plants. In January 2012, the EIA projected total annual domestic consumption of natural gas to increase from approximately 22.9 Tcf in 2009 to approximately 26.5 Tcf in 2035. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2035 to 27.8 Tcf. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long-term throughout the United States.

100

---

Growth in production from U.S. shale plays

        Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds). While the EIA expects total domestic natural gas production to grow from 20.6 Tcf in 2009 to 27.8 Tcf in 2035, it expects shale gas production to grow to 13.6 Tcf in 2035, or 49% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics as compared to most conventional plays.

        In recent years, well-capitalized producers have leased large acreage positions in the Piceance Basin, the Barnett Shale and other unconventional resource plays. To help fund their drilling program in many of these areas, including in the Piceance Basin and the Barnett Shale, a number of producers have also entered into joint venture arrangements with large international operators and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin, the Barnett Shale and other unconventional resource plays, which we believe will result in sustained drilling activity.

        As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.

Interest rate environment

        The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Rising operating costs and inflation

        The current high level of natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

101

---

Results of Operations—Combined Overview

        The following table and discussion presents certain historical consolidated financial data of our Predecessor for the periods indicated.

102

---

Items Affecting the Comparability of Our Financial Results

        The historical results of operations of our Predecessor may not be comparable to our future results of operations for the reasons described below:

•

Because we acquired our initial interest in the DFW Midstream system from Texas Competitive Electric Holdings Company, LLC ("TCEH"), an indirect subsidiary of Energy Future Holdings Corp., effective as of September 3, 2009, the financial and operational data for 2009 that is presented and discussed in this prospectus is generally bifurcated between the period that our Initial Predecessor owned those assets and the period from the acquisition of those assets by Summit Midstream Predecessor through December 31, 2009.



•

The historical consolidated financial statements and related notes of our Initial Predecessor:



•

have been carved out of the accounting records maintained by Energy Future Holdings and its subsidiaries. Certain accounts such as trade accounts receivables, accounts payable, pre-paid expenses and certain accrued liabilities relating to the activities of our Initial Predecessor were recorded on the books of other Energy Future Holdings entities and estimates of those accounts have been included in the consolidated financial statements;



•

include an estimate for general and administrative ("G&A") expenses, as Energy Future Holdings did not allocate any of the central finance and administrative costs to this operating entity;



•

reflect the operation of the DFW Midstream system with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate it. Please read "Business—Business Strategies;" and



•

do not include any results from certain natural gas gathering assets that we acquired from Chesapeake Energy Corporation on September 3, 2009 that are included in the DFW Midstream system.



•

The historical consolidated financial statements and related notes of Summit Midstream Predecessor:



•

reflect a 75% ownership interest in the entity we acquired from TCEH from September 4, 2009 to June 18, 2010, the date on which Summit Midstream Predecessor purchased the remaining 25% membership interest from TCEH for $90.7 million;

103

---

•

include transaction expenses of $3.9 million in 2009 that we incurred in connection with our formation and our initial acquisition of assets. These expenses include an aggregate of $2.2 million paid to Energy Capital Partners and $1.7 million paid to third parties for strategic, advisory, management, legal, and consulting services;



•

include charges associated with a transition services agreement that we entered into with Energy Future Holdings effective September 3, 2009. Under the terms of the transition services agreement, we paid Energy Future Holdings $38,700, $0.1 million and $0.1 million for the years ended December 31, 2011 and 2010 and the period from September 3, 2009 through December 31, 2009, respectively; and



•

do not include any results from the acquisition of the Grand River system prior to November 2011.



•

We anticipate incurring approximately $2.5 million of G&A expense attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs, and director compensation. These incremental G&A expenses are not reflected in the historical consolidated financial statements of our Initial Predecessor or Summit Midstream Predecessor.



•

Following the closing of this offering, we intend to make cash distributions to our unitholders equal to our minimum quarterly distribution of $             per unit per quarter ($             per unit on an annualized basis). Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our amended and restated revolving credit facility and future issuances of equity and debt securities. Historically, Summit Midstream Predecessor largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy its capital expenditure requirements.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

        Volume.    Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 623.2 MMcf/d, or 219%, from 285.2 MMcf/d for the three months ended March 31, 2011 to 908.4 MMcf/d for the three months ended March 31, 2012. This increase is due to the continued development of the DFW Midstream system and the acquisition of the Grand River system. There were 307 wells and 61 drilling pad sites and 187 wells and 40 drilling pad sites connected to the DFW Midstream system as of March 31, 2012 and 2011, respectively. The DFW Midstream system included 110 miles and 86 miles of pipeline as of March 31, 2012 and 2011, respectively. Throughput volumes for the DFW Midstream system averaged 314.8 MMcf/d for the three months ended March 31, 2012. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 593.6 MMcf/d for the three months ended March 31, 2012.

        Revenue.    Total revenue increased $16.6 million, or 87%, from $19.2 million for the three months ended March 31, 2011 to $35.8 million for the three months ended March 31, 2012. Gathering services and other fees increased $14.8 million, or 86%, from $17.1 million for the three months ended March 31, 2011 to $31.9 million for the three months ended March 31, 2012. This increase was primarily the result of increased throughput volumes on the DFW Midstream system, offset by a

104

---

decrease of $0.15 per Mcf, or 17%, in the average throughput rates from $0.52 per Mcf for the three months ended March 31, 2011 to $0.37 per Mcf for the three months ended March 31, 2012. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $15.7 million for the three months ended March 31, 2012. Natural gas and condensate sales increased $1.6 million, or 76%, from $2.1 million for the three months ended March 31, 2011 to $3.7 million for the three months ended March 31, 2012. The increase in revenue attributable to natural gas and condensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the Grand River system was $1.3 million for the three months ended March 31, 2012.

        Operations and maintenance expense.    Operations and maintenance expense increased $4.8 million, or 79%, from $6.1 million for the three months ended March 31, 2011 to $11.0 million for the three months ended March 31, 2012. This increase was primarily the result of operations and maintenance expense for the Grand River system of $5.8 million for the three months ended March 31, 2012. Ad valorem taxes increased approximately $0.4 million on the DFW Midstream system for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. The increase in operations and maintenance expense was offset by a $0.6 million reduction in CO₂ related expenses for the three months ended March 31, 2012 compared to the comparable period in 2011. Compressor related expenses decreased $0.3 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 due to cancellation of a third-party compressor operating agreement in the fourth quarter of 2011.

        General and administrative ("G&A") expense.    G&A expense increased $0.6 million, or 15%, from $3.8 million for the three months ended March 31, 2011 to $4.4 million for the three months ended March 31, 2012. Salary and benefit expenses increased $0.9 million, or 70%, from $1.3 million for the three months ended March 31, 2011 to $2.3 million for the three months ended March 31, 2012 due to increased headcount to support our growth. Insurance related costs increased $0.3 million and employee related costs increased $0.3 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 as a result of the acquisition of the Grand River system in October 2011. The increase in G&A expenses was partially offset by a decrease in non-cash unit based compensation for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. Non-cash unit based compensation expense relative to net profits interests held by certain current and former members of management decreased $0.8 million, or 62%, from $1.2 million for the three months ended March 31, 2011 to $0.5 million for the three months ended March 31, 2012.

        Depreciation and amortization expense.    Depreciation and amortization expense increased $6.7 million, or 417%, from $1.6 million for the three months ended March 31, 2011 to $8.3 million for the three months ended March 31, 2012. This increase was primarily the result of the depreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system during 2011. Depreciation and amortization expense for the Grand River system was $5.4 million for the three months ended March 31, 2012.

        Interest expense and affiliated interest expense.    Interest expense increased $4.2 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. This increase was primarily the result of entering into our revolving credit facility in May 2011 and issuing $200 million of promissory notes to our sponsors in connection with the acquisition of the Grand River system. We did not have a revolving credit facility or outstanding promissory notes during the three months ended March 31, 2011.

105

---

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        Volume.    Our revenues are primarily attributable to the volume of natural gas that we gather and the rates we charge to gather that natural gas. Throughput volumes increased 293.7 MMcf/d, or 219%, from 134.3 MMcf/d for the year ended December 31, 2010 to 428.0 MMcf/d for the year ended December 31, 2011. This increase was due to the continued development of the DFW Midstream system. There were 275 wells and 58 drilling pad sites and 160 wells and 33 drilling pad sites connected to the DFW Midstream system as of December 31, 2011 and 2010, respectively. The DFW Midstream system included 104 miles and 83 miles of pipeline as of December 31, 2011 and December 31, 2010, respectively. Throughput volumes for the DFW Midstream system averaged 329.0 MMcf/d for the year ended December 31, 2011. We acquired the Grand River system in October 2011. Throughput volumes for the Grand River system averaged 605.9 MMcf/d for the two months that are included in our financial results for the year ended December 31, 2011.

        Revenue.    Total revenue increased $71.9 million, or 227%, from $31.7 million for the year ended December 31, 2010 to $103.6 million for the year ended December 31, 2011. Gathering services and other fees increased $62.1 million, or 211%, from $29.4 million for the year ended December 31, 2010 to $91.4 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system, offset by a decrease of $0.04 per Mcf, or 7%, in the average throughput rates from $0.57 per Mcf for the year ended December 31, 2010 to $0.53 per Mcf for the year ended December 31, 2011. This decrease is primarily due to the fact that the Grand River system generates a lower average gathering fee per Mcf than our DFW Midstream system. Gas gathering revenue for the Grand River system was $11.0 million for the two months that are included in our financial results for the year ended December 31, 2011. Natural gas and condensate sales increased $9.9 million, or 391%, from $2.5 million for the year ended December 31, 2010 to $12.4 million for the year ended December 31, 2011. The increase in revenue attributable to natural gas and condensate sales is primarily the result of increased sales of natural gas that we retain from our DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale. Revenue associated with condensate sales for the Grand River system was $0.6 million for the two months ended December 31, 2011.

        Operations and maintenance expense.    Operations and maintenance expense increased $20.4 million, or 214%, from $9.5 million for the year ended December 31, 2010 to $29.9 million for the year ended December 31, 2011. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors increased $9.1 million, or 206%, from $4.4 million for the year ended December 31, 2010 to $13.5 million for the year ended December 31, 2011 due to increased volumes and the associated increased power cost to operate the compression. Operations and maintenance expenses for the Grand River system were $3.9 million for the two months that are included in our financial results for the year ended December 31, 2011.

        General and administrative expense.    G&A expense increased $7.4 million, or 74%, from $10.0 million for the year ended December 31, 2010 to $17.5 million for the year ended December 31, 2011. We recorded non-cash compensation expense of $3.4 million for the year ended December 31, 2011 relative to profits interests held by certain members of management. We did not record non-cash compensation expense for the year ended December 31, 2010. Salary and benefit expenses increased $2.0 million, or 45%, from $4.3 million for the year ended December 31, 2010 to $6.3 million for the year ended December 31, 2011 due to increased headcount to support our growth. We did not have these expenses for the year ended December 31, 2010. Due diligence costs relative to potential asset acquisitions were $1.3 million in 2011 compared to insignificant due diligence costs in 2010. The increase in G&A expenses was offset by decreases in legal expenses for the year ended December 31, 2011 compared to the year ended December 31, 2010. Legal expenses decreased $2.0 million in 2011 primarily as the result of decreased legal activities relative to relationships with contractors and

106

---

sub-contractors associated with the DFW Midstream system. We had $1.8 million in settlement expenses in 2010 related to a dispute with a contractor at the DFW Midstream system.

        Transaction costs.    Transaction costs were $3.2 million for the year ended December 31, 2011. These transaction costs were primarily related to the acquisition of the Grand River system. We did not have transaction costs for the year ended December 31, 2010.

        Depreciation and amortization expense.    Depreciation and amortization expense increased $8.1 million, or 208%, from $3.9 million for the year ended December 31, 2010 to $12.0 million for the year ended December 31, 2011. This increase was primarily the result of the depreciation associated with additional assets placed into service in connection with the development of the DFW Midstream system in 2011. Depreciation and amortization expense for the Grand River system was $3.8 million for the two months that are included in our financial results for the year ended December 31, 2011.

        Interest expense and affiliated interest expense.    Interest expense increased $3.1 million for the year ended December 31, 2011. This increase was primarily the result of entering into our revolving credit facility in May 2011 and the related amortization of deferred loan costs of $0.6 million and issuing $200 million of promissory notes to our sponsors in connection with the acquisition of the Grand River system. We did not have a revolving credit facility or outstanding promissory notes in 2010 and, therefore, we had no interest expense for the year ended December 31, 2010.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

        Volume.    Throughput volumes increased 118.6 MMcf/d, or 755%, from 15.7 MMcf/d for the 2009 Initial Predecessor Period to 134.3 MMcf/d for the year ended December 31, 2010. Throughput volumes increased 118.9 MMcf/d, or 772%, from 15.4 MMcf/d for the 2009 Summit Midstream Predecessor Period to 134.3 MMcf/d for the year ended December 31, 2010. Throughput volumes increased significantly for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period due to the continued development of the DFW Midstream system. There were 160 wells and 33 drilling pad sites and 20 wells and 4 drilling pad sites connected to the DFW Midstream system as of December 31, 2010 and December 31, 2009, respectively. The DFW Midstream system included 83 miles and 12 miles of pipeline as of December 31, 2010 and December 31, 2009, respectively.

        Revenue.    Revenue increased $28.0 million, or 770%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $31.7 million for the year ended December 31, 2010. Gas gathering revenue increased $25.8 million, or 710%, from $1.9 million for the 2009 Initial Predecessor Period and $1.7 million for the 2009 Summit Midstream Predecessor Period to $29.4 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Average throughput rates decreased $0.01 per Mcf, or 2%, from $0.58 per Mcf for the 2009 Summit Midstream Predecessor Period to $0.57 per Mcf for the year ended December 31, 2010. Natural gas and condensate sales were $2.5 million for the year ended December 31, 2010. Revenue for the year ended December 31, 2010 included sales of natural gas that we retain from DFW Midstream customers to offset the costs we incur to operate our electric-drive compression assets in the Barnett Shale.

        Operations and maintenance expense.    Operations and maintenance expense increased $7.3 million, or 341%, from $1.0 million for the 2009 Initial Predecessor Period and $1.1 million for the 2009 Summit Midstream Predecessor Period to $9.5 million for the year ended December 31, 2010. This increase was primarily the result of increased throughput volumes on the DFW Midstream system. Utility expense for our electric drive compressors were $4.4 million for the year ended December 31, 2010. Utility expense for the 2009 Initial Predecessor Period and for the 2009 Summit Midstream

107

---

Predecessor Period was insignificant. The remaining increase in operations and maintenance expense for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period was primarily the result of additional throughput on the DFW Midstream system and additional compression being placed into service.

        General and administrative expense.    G&A expense increased $6.5 million, or 184%, from $0.6 million for the 2009 Initial Predecessor Period and $2.9 million for the 2009 Summit Midstream Predecessor Period to $10.0 million for the year ended December 31, 2010. Legal expenses increased $2.0 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period primarily as the result of legal activities relative to relationships with contractors and sub-contractors associated with the DFW Midstream system. The remaining increase in G&A expenses for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period is the result of our ownership of the DFW Midstream system for the full year 2010. We acquired our initial assets of our DFW Midstream system effective as of September 3, 2009. Additionally, we increased our headcount in 2010 compared to 2009 as we continued construction and development of the DFW Midstream system.

        Transaction costs.    Transaction costs were $3.9 million for the 2009 Summit Midstream Predecessor Period. These transaction costs were primarily related to the acquisition of the DFW Midstream system in September 2009. We did not have transaction costs for the 2009 Initial Predecessor Period or the year ended December 31, 2010.

        Depreciation and amortization expense.    Depreciation and amortization expense increased $2.6 million, or 216%, from $0.9 million for the 2009 Initial Predecessor Period and $0.3 million for the 2009 Summit Midstream Predecessor Period to $3.9 million for the year ended December 31, 2010. This increase was primarily the result of the depreciation associated with assets placed into service in connection with the expansion and development of the DFW Midstream system in 2010.

        Interest expense.    Interest expense decreased $0.2 million for the year ended December 31, 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. Interest expense for the 2009 Initial Predecessor Period included $0.2 million related to an intercompany capital allocation charge during the ownership of the DFW Midstream system by our Initial Predecessor. We did not have an intercompany capital allocation charge for the year ended December 31, 2010.

Liquidity and Capital Resources

        Since the acquisition of our initial assets in September 2009, our sources of liquidity have included cash generated from operations, equity investments by our sponsors, Energy Capital Partners and GE Energy Financial Services, and borrowings under our revolving credit facility.

        Following the closing of this offering we expect our sources of liquidity to include:

•

cash generated from operations;



•

borrowings under our amended and restated revolving credit facility; and



•

issuances of debt and equity securities.

        We believe that the cash generated from these sources will be sufficient to allow us to distribute the minimum quarterly distribution to all of our unitholders and the corresponding distribution on our 2.0% general partner interest and to meet our requirements for working capital and capital expenditures for the foreseeable future.

108

---

Cash Flows

        The following table reflects cash flows for the applicable periods:

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

        Operating activities.    Cash flows from operating activities increased by $7.7 million, or 87%, from $8.9 million for the three months ended March 31, 2011 to $16.6 million for the three months ended March 31, 2012. The increase in cash flows from operating activities is a direct result of the increase in volumes on the DFW Midstream system for the three months ended March 31, 2012 compared to three months ended March 31, 2011 and the inclusion of operations on the Grand River system for the three months ended March 31, 2012.

        Investing activities.    Cash flows used for investing activities increased by $1.0 million, or 5.1%, from $19.6 million for the three months ended March 31, 2011 to $20.6 million for the three months ended March 31, 2012. Capital expenditures on the DFW Midstream system decreased $5.0 million, or 25%, from $19.6 million for the three months ended March 31, 2011 to $14.6 million for the three months ended March 31, 2012. Capital expenditures on the Grand River system were $5.6 million for the three months ended March 31, 2012.

        Financing activities.    Cash flows from financing activities were $8.0 million for the three months ended March 31, 2011 and consisted of capital contributions from Energy Capital Partners to support capital needs related to the construction of the DFW Midstream system. No capital contributions were made during the three months ended March 31, 2012. Cash flows from financing activities of $0.6 million for the three months ended March 31, 2012 consisted of deferred loan costs and initial public offering costs.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        Operating activities.    Cash flows from operating activities increased by $30.4 million, or 318%, from $9.6 million for the year ended December 31, 2010 to $40.0 million for the year ended December 31, 2011. The increase in cash flows from operating activities is a direct result of the significant increase in volumes on the DFW Midstream system during 2011 compared to 2010 and the inclusion of two months of operations on the Grand River system for the year ended December 31, 2011.

        Investing activities.    Cash flows used for investing activities increased by $514.0 million, or 334%, from $153.7 million for the year ended December 31, 2010 to $667.7 million for the year ended December 31, 2011. The increase in cash flows used for investing activities is primarily due to the acquisition of the Grand River system for $590.0 million. Capital expenditures decreased by $79.2 million, or 49%, from $154.0 million for the year ended December 31, 2010 to $74.8 million for the year ended December 31, 2011. Capital expenditures in 2010 were higher due to the installation and commissioning of compressor stations on the DFW Midstream system.

109

---

        Financing activities.    Cash flows from financing activities increased by $519.7 million, or 455%, from $114.1 million for the year ended December 31, 2010 to $633.8 million for the year ended December 31, 2011. The increase in cash flows from financing activities is primarily due to the acquisition of the Grand River system. Summit Midstream Predecessor received equity contributions of $410 million and a $200.0 million non-recourse loan from Energy Capital Partners and GE Energy Financial Services to acquire the Grand River system. Summit Midstream Predecessor closed on our revolving credit facility in May 2011. Upon closing the revolving credit facility, Summit Midstream Predecessor made a distribution to our sponsors of $132.9 million of the $142.0 million drawn at closing.

Year Ended December 31, 2010 Compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period

        Operating activities.    Cash flows from operating activities increased by $15.2 million from $0.6 million for the 2009 Initial Predecessor Period and $(6.2) million for the 2009 Summit Midstream Predecessor Period to $9.6 million for the year ended December 31, 2010. The increase in cash flows from operating activities is related to the increased volumes on the DFW Midstream system during 2010 compared to the 2009 Initial Predecessor Period and the 2009 Summit Midstream Predecessor Period. The increase in volumes resulted in an increase of net income by $15.6 million, from $(0.8) million for the 2009 Initial Predecessor Period and $(6.6) million for the 2009 Summit Midstream Predecessor Period to $8.2 million for the year ended December 31, 2010.

        Investing activities.    Cash flows used for investing activities increased by $48.5 million, or 46%, from $40.8 million for the 2009 Initial Predecessor Period and $64.4 million for the 2009 Summit Midstream Predecessor Period to $153.7 million for the year ended December 31, 2010. The cash used for investing activities increased due to the installation and commissioning of the compressor stations on the DFW Midstream system during 2010.

        Financing activities.    The cash flows from financing activities during the 2009 Initial Predecessor Period, the 2009 Summit Midstream Predecessor Period and the year ended December 31, 2010 were capital contributions from Energy Capital Partners. During the 2009 Summit Midstream Predecessor Period, Energy Capital Partners contributed $107.0 million at formation and then contributed an additional $27.9 million to support capital needs related to the construction of the DFW Midstream system. In the year ended December 31, 2010, Energy Capital Partners contributed $194.1 million in support of the continued growth and construction of the DFW Midstream system. In June 2010, we purchased the remainder of Energy Future Holdings' membership interests related to the DFW Midstream system for $90.7 million, which was funded with the capital contributed by Energy Capital Partners.

Off-Balance Sheet Arrangements

        We do not have any off-balance sheet arrangements.

Capital Requirements

        The natural gas gathering segment of the midstream energy business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

•

maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

110

---

•

expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term.

        For the year ended December 31, 2011, our total capital expenditures were $667.7 million. Approximately $590.0 million of the capital expenditures in 2011 were related to our acquisition of the Grand River system in October 2011. The remainder were primarily associated with the construction of new pipeline infrastructure to connect new pad sites on our DFW Midstream system and to connect new pad sites and central receipt points on our Grand River system. Historically, we did not make a distinction between maintenance and expansion capital expenditures. We have estimated, however, that approximately $3.1 million of these capital expenditures were maintenance capital expenditures.

        We are forecasting $78.2 million in capital expenditures for the year ending December 31, 2012, of which $73.0 million represents expansion capital expenditures and $5.2 million represents maintenance capital expenditures. Our 2012 budgeted expansion capital expenditures include:

•

$16.4 million to construct pipeline laterals and tie in additional pad sites for customers on the DFW Midstream system;



•

$13.7 million related to the installation of additional compression assets and construction of several looping pipelines on the DFW Midstream system in order to increase system capacity to over 450 MMcf/d and optimize throughput hydraulics and operating pressures;



•

$11.8 million related to the construction of medium-pressure pipelines and the installation of additional compression-related assets in the Orchard field on the Grand River system;



•

$10.0 million associated with the procurement and installation of pad site meter equipment at approximately 400 existing pad sites on the Grand River system;



•

$9.4 million to expand and improve hydraulic efficiency of our assets in the Mamm Creek field on the Grand River system; and



•

$5.7 million to connect five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.

        As of March 31, 2012, we have spent approximately $20.6 million of our 2012 expansion capital budget.

        We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our amended and restated revolving credit facility and the issuance of debt and equity securities.

Distributions

        We intend to pay a quarterly distribution at an initial rate of $            per unit, which equates to an aggregate distribution of $             million per quarter, or $             million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering and the related distributions on our 2.0% general partner interest. We do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our Amended and Restated Revolving Credit Facility

        Effective May 7, 2012, we amended and restated our revolving credit facility with a syndicate of lenders to increase our borrowing capacity from $285 million to $550 million. Substantially all of our assets are pledged as collateral under our amended and restated revolving credit facility. The amended and restated revolving credit facility matures in May 2016 and, at our option, borrowings thereunder bear interest at a variable rate per annum equal to either LIBOR, plus the applicable margins ranging

111

---

from 2.5% to 3.5%, or at a base rate, plus the applicable margins ranging from 1.5% to 2.5%. The events that constitute an event of default under our amended and restated revolving credit facility are customary for credit facilities of this size and nature.

        Our amended and restated credit agreement contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:

•

permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to be less than 2.50 to 1.00;



•

permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to be above 5.00 to 1.00 (or 5.50 to 1.00 if we have made certain business acquisitions);



•

incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject to customary exceptions for permitted liens;



•

make any investments, subject to customary exceptions for certain permitted investments;



•

engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactions of such types;



•

pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants under the amended and restated credit agreement;



•

enter into any swap agreements or power purchase agreements, subject to customary exceptions, such as the entry into swap agreements and power purchase agreements in the ordinary course of business; and



•

enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.

        As of March 31, 2012, we were in compliance with the financial and other covenants in our amended and restated revolving credit facility.

        In addition to the uses described in "Use of Proceeds," we expect borrowings under our amended and restated revolving credit facility to be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) capital expenditures. There was $352.0 million drawn under our amended and restated revolving credit facility at July 16, 2012.

Promissory Notes Payable to Sponsors

        In connection with our acquisition of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million and had an 8% interest rate and a maturity date of October 27, 2013. Summit Investments exercised its option to make a payment in kind for all interest due as of March 31, 2012. The amount of interest paid in kind and accrued to the balance of the notes as of March 31, 2012 was $6.9 million, resulting in $206.9 million as the amount outstanding on the notes as of March 31, 2012. During 2011 and the three months ended March 31, 2012, Summit Investments capitalized $0.9 million of the $2.9 million interest expense and $0.6 million of the $4.0 million interest expense, respectively, related to costs incurred on capital projects under construction. As of March 31, 2012, the aggregate carrying value of these notes approximated the fair value.

        The promissory notes payable to our sponsors were repaid in full on July 2, 2012.

112

---

Credit Risk and Customer Concentration

        We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. A significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. Chesapeake, Carrizo, TOTAL and Energy Transfer Fuels each accounted for more than 10% of our $103.6 million in consolidated revenue for the year ended December 31, 2011, accounting for 34%, 17%, 10% and 12%, respectively, of our consolidated revenue for that year. Although we have contractual arrangements with each of these counterparties of varying duration, if one or more of these customers were to default on their contractual obligations or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.

Contractual Obligations

        The table below summarizes our contractual obligations and other commitments as of December 31, 2011:

Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

        We have exposure to changes in interest rates on our indebtedness associated with our amended and restated revolving credit facility. The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

        Summit Midstream Predecessor entered into our revolving credit facility in May 2011, which was amended and restated on May 7, 2012. A hypothetical increase or decrease in interest rates of 1.0% would have increased or decreased, respectively, our interest expense by $1.5 million for the year ended December 31, 2011.

113

---

Commodity Price Risk

        Because we currently generate a substantial majority of our revenues pursuant to long-term, fixed-fee gas gathering agreements that include minimum volume commitments and AMIs, our only direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system and (iii) the sale of condensate volumes that we collect on the Grand River system. Our gas gathering agreements with our Barnett Shale customers permit us to retain a certain quantity of natural gas that is intended to offset the power costs we incur to operate our electric-drive compression assets. Our gas gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices at the Waha Hub Index. Because we also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas sales. We do not enter into risk management contracts for speculative purposes.

Impact of Seasonality

        Our results of operations on our gathering systems are not materially affected by seasonality.

Critical Accounting Policies and Estimates

        In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities as of the balance sheet date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses, including fair value measurements and disclosure of contingencies, during the reporting period. Our actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the accounting policies currently underlying our most significant financial statement items:

Contingencies

        The financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.

Depreciation

        Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property, plant and equipment and revise our estimates. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.

Property, Plant and Equipment

        Property, plant, and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of

114

---

the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirement of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in the statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

Impairment of Long-Lived Assets

        Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposal of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows.

Compensatory Awards

        Certain of our current and former employees were granted Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC. We refer to these interests collectively as the net profits interests. The net profits interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested net profits interests. The net profits interests are accounted for as compensatory awards. The net profits interests vest ratably over four to five years, and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Summit Midstream Partners LLC Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the net profits interests as of the respective grant dates. The net profits interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the net profits interests: (a) assumptions underlying the enterprise value used in connection with the option pricing method, including the discount rate applied to estimated future cash flows, forecasted gathering volumes, revenues and costs, equity performance relative to peer group members, equity market risk premium, enterprise-specific risk premium, and terminal growth rates; (b) holding period restrictions; (c) discounts for lack of marketability; and (d) expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

Revenue Recognition

        We earn revenue from natural gas gathering services provided to natural gas producers and record such revenue as gathering services and other fees. We also earn revenue from the sale of physical natural gas retained from our customers to offset power expenses associated with electric-driven compression on the DFW Midstream system. We record this revenue as fuel retainage revenue. We record costs incurred which are reimbursed by our customers, on a gross basis in the consolidated statement of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured.

115

---

        Our gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from our customers. Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. We recognize the revenue associated with MVC shortfall payments upon expiration of the applicable contract month or year. Under certain gas gathering agreements, our customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that its throughput volumes in subsequent years exceed its MVC.

116

---

INDUSTRY OVERVIEW

General

        The midstream natural gas industry is the link between the exploration and production of natural gas from the wellhead or lease and the delivery of the natural gas and its other components to end-use markets. Companies within this industry create value at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and natural gas liquids, or NGLs, and then routing the separated dry gas and NGL streams for delivery to end-markets or to the next intermediate stage of the value chain.

        The following diagram illustrates the groups of assets commonly found along the natural gas value chain:

Midstream Services

        The range of services utilized by midstream natural gas service providers are generally divided into the following categories:

Gathering

        At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression

        Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression,

117

---

volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration

        Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing

        The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation

        The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.

Transportation and Storage

        Once the raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.

Contractual Arrangements

        Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical types of contracts are described below.

118

---

Fee-Based

        Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure.

Percent-of-Proceeds

        Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.

Keep-Whole

        Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processor compensates the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

        There are two forms of contracts utilized in the transportation and storage of natural gas:

Firm

        Firm service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a "demand" or "capacity reservation" fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas gathered. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.

Interruptible

        Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Market Fundamentals

Natural Gas Demand

        Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 25% of all energy used in the United States in 2010, representing 24 Tcf of natural gas. The EIA estimates that over the next 25 years, total domestic energy consumption will increase by over 10%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and

119

---

natural gas vehicles. The following charts show the allocation of natural gas usage by end user as well as the relative position of natural gas as a power generation fuel source as of 2010.

Source: EIA, Annual Energy Outlook 2012 Early Release (January 2012).

        According to the EIA, as shown in the chart below, during the period from 2001 through 2010, natural gas consumption increased by 9.6% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 66.8 Bcf/d in 2011. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation and commercial/residential sectors, where consumption grew by approximately 42.3% and 1.3%, respectively. The growth in these sectors was partially offset by an approximate 7.6% decline in natural gas consumption in the less seasonal industrial sector.

U.S. Annual & Average Daily Natural Gas Consumption

Source: EIA, U.S. Natural Gas Consumption by End Use (April 2012).

        Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased

120

---

likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 24.3 Tcf in 2010 to 26.5 Tcf in 2035.

Natural Gas Supply

        Domestic natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 32.4% in 2010. According to EIA data, during the three-year period from January 2007 through December 2010 domestic production of natural gas increased by an average of approximately 3.8% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

        In 2011, the EIA estimated that the United States held 827 Tcf of technically recoverable shale gas resource. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 49% in 2035 as compared with 23% in 2010.

121

---

Natural Gas Production by Source, 1990-2035

Source: EIA, Annual Energy Outlook 2012 Early Release (January 2012).

122

---

BUSINESS

Overview

        We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas. As of May 31, 2012, our gathering systems had approximately 386 miles of pipeline and 147,600 horsepower of compression. During the first quarter of 2012, our systems gathered an average of approximately 908 MMcf/d of natural gas, of which approximately 62% contained NGLs that were extracted by a third party processor. We believe that we are positioned to grow through the increased utilization and further development of our existing assets. In addition, we intend to grow our business through strategic partnerships with large producers to provide midstream services for their upstream development projects, as well as through acquisitions in our existing areas of operation and in new areas.

        We generate a substantial majority of our revenue under long-term fee-based, natural gas gathering agreements. Our customers include some of the largest natural gas producers in North America, such as Encana Corporation, Chesapeake Energy Corporation, TOTAL, S.A., Carrizo Oil & Gas, Inc., WPX Energy, Inc., Bill Barrett Corporation, Exxon Mobil Corporation and EOG Resources, Inc.

        Substantially all of our gas gathering agreements are underpinned by areas of mutual interest, or AMIs, and minimum volume commitments. Our AMIs cover approximately 330,000 acres in the aggregate, have original terms that range from 10 years to 25 years, and provide that any production from natural gas wells drilled by our customers within the AMIs will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.6 Tcf at March 31, 2012 and, through 2020, average approximately 643 MMcf/d, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from 7 years to 15 years and, as of March 31, 2012, had a weighted average remaining life of 11.6 years assuming minimum throughput volume for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

        We were formed in 2009 by members of our management team and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. We are currently owned by Energy Capital Partners, GE Energy Financial Services, a global investor in essential, long-lived and capital intensive energy assets with over $20 billion in energy investments worldwide, and certain members of our management team.

        For the year ended December 31, 2011, we generated $103.6 million of revenue, $37.4 million of net income and $60.0 million of Adjusted EBITDA. These amounts reflect only two months of operations from our Grand River system, which we acquired in October 2011. Please read "—Our Assets—Grand River System." For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical Financial and Operating Data—Non-GAAP Financial Measure."

        Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are summarized below.

123

---

Grand River System

        In October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin of western Colorado, which we refer to as the Grand River system, from Encana for $590 million. The Grand River system comprises approximately 276 miles of pipeline and 97,500 horsepower of compression and is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado. All of the natural gas gathered on the Grand River system is discharged to Enterprise Products Partners L.P.'s pipeline serving its 1.7 Bcf/d processing facility located in Meeker, Colorado. For the quarter ended March 31, 2012, the Grand River system gathered an average of approximately 593 MMcf/d from five producers, including Encana as the anchor customer.

        The Grand River system primarily gathers natural gas produced by our customers from the liquids-rich Mesaverde formation within the Piceance Basin. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling activities for several decades. The Grand River system also gathers natural gas produced from our customers' wells targeting the deeper Mancos and Niobrara Shale formations, which have higher initial production rates and lower Btu gas content than Mesaverde wells. Over the last two years, our customers have completed numerous horizontal wells targeting the emerging Mancos and Niobrara Shale formations. Based on our customers' current drilling expectations, we anticipate the majority of our near-term throughput on the Grand River system will continue to be comprised of Mesaverde formation production.

        We intend to expand the Grand River system by connecting additional pad sites within our AMIs, adding new customers and acquiring nearby gathering systems. We expect that, to the extent natural gas prices increase from current levels, our customers will accelerate drilling activities targeting the Mancos and Niobrara shale formations, which will provide us with an opportunity to construct a new medium pressure pipeline system to gather the resulting production and increase throughput on the Grand River system.

DFW Midstream System

        In September 2009, we acquired approximately 17 miles of pipeline and 2,500 horsepower of electric-drive compression in north-central Texas, which we refer to as the DFW Midstream system, from Energy Future Holdings and Chesapeake. Since the initial acquisition, we have expanded the DFW Midstream system by adding approximately 93 miles of pipeline to connect 62 of 73 currently identified pad sites and installing an incremental 47,600 horsepower of electric-drive compression. The DFW Midstream system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers, directly or indirectly, with the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana. For the quarter ended March 31, 2012, the DFW Midstream system gathered an average of approximately 315 MMcf/d from six producers.

        Our DFW Midstream system benefits from its location within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale formation. This area is commonly referred to as the core of the Barnett Shale and, according to the Texas Railroad Commission, contains the most prolific wells drilled in the Barnett Shale to date based on peak month daily average production rates. Construction of the DFW Midstream system is substantially complete and enables our customers to efficiently produce natural gas by utilizing horizontal drilling techniques throughout the vast majority of our AMIs from pad sites already connected to the DFW Midstream system. Given the urban nature of our area of operations, in what we consider to be the "core of the core" of the Barnett Shale, we expect that the majority of future natural gas drilling in this area will occur from these existing connected pad sites, which should enable us to increase throughput and cash flows with minimal additional capital expenditures.

124

---

Business Strategies

        Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:

•

Increasing capacity of and throughput volumes on our existing systems.  We intend to continue to focus on maximizing the utilization of our assets by increasing volume throughput from existing customers and connecting new customers to our systems. The DFW Midstream system is designed to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the DFW Midstream system and do not require significant additional capital expenditures. In addition, we seek to optimize our existing systems by adding third-party volumes that in general would not otherwise be pursued by large upstream producers who are primarily focused on gathering their own production volumes.



•

Capitalizing on organic growth opportunities.  Our existing gathering systems provide us with significant organic expansion opportunities. We intend to leverage our management team's expertise in constructing, developing and optimizing midstream infrastructure assets to grow our business through organic development projects that are designed to extend our geographic reach, diversify our customer base, increase the number of our natural gas receipt points and maximize volume throughput. Our expansion of the DFW Midstream system is expected to increase the system to approximately 120 miles of 8 inch to 30 inch pipeline and 56,100 horsepower of electric-drive compression. This expansion includes installing additional electric-drive compression that we expect will increase throughput capacity on the DFW Midstream system from 410 MMcf/d to over 450 MMcf/d. We expect that this incremental throughput capacity will be utilized by our existing customers who we expect to drill on previously connected pad sites and new pad sites that we will connect to our system. We expect pad site connections to increase from 62 as of April 2012 to 73 by the end of 2013. Additional projects that we expect to undertake during 2012 include:



•

Connecting five pad sites adjacent to the DFW Midstream system for our new customer, Beacon E&P.



•

Continuing the construction of a new medium-pressure gathering system alongside portions of our existing low-pressure system in the Piceance Basin. In connection with our acquisition of the Grand River system, we entered into a contractual arrangement with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.



•

Pursuing new customers currently operating in close proximity to our existing gathering infrastructure in the Barnett Shale and the Piceance Basin in order to maximize system capacity utilization. We have successfully pursued this strategy since acquiring the DFW Midstream system in 2009 and it is highlighted by our addition of EOG, Vantage Energy and Beacon E&P as new customers in 2009, 2010 and 2012, respectively. We will continue to pursue this strategy in the Barnett Shale and the Piceance Basin and are currently in discussions with multiple producers to expand our asset footprint and increase our natural gas receipt points.



•

Maintaining our focus on fee-based revenue with minimal direct commodity price exposure.  As we expand our business, we intend to maintain our focus on providing midstream energy services under fee-based arrangements. Our midstream services are almost exclusively provided under long-term, fee-based contracts with original terms ranging from 10 years to 25 years. We do not take title to the natural gas that we gather for our customers and, as a result, our business is not directly exposed to commodity price fluctuations. In addition, we have secured AMIs from certain of our customers covering all of their natural gas production from approximately 230,000 acres in the Piceance Basin and 100,000 acres in the Barnett Shale. We believe that our

125

---

focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows and increasing our quarterly distributions over time.

•

Partnering with large natural gas producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We pursue opportunities to partner with established producers in unconventional resource basins to develop new infrastructure that we believe will complement our existing midstream assets or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of a strategic acreage position in an unconventional resource play and represent assets that are well-positioned for accelerated production growth but have minimal existing midstream energy infrastructure to support such growth. We have been successful with this strategy and will continue to pursue similar opportunities that utilize our management team's experience in constructing, developing and operating large scale midstream infrastructure. We seek to promote commercial relationships with established producers, such as Encana on the Grand River system and Chesapeake on the DFW Midstream system, who are willing to serve as an anchor customer and are willing to commit to long-term volume and AMIs.



•

Diversifying our asset base by exploring acquisition and development opportunities in various geographical areas and other sectors of the midstream industry. While our natural gas gathering operations in the Piceance Basin and the Barnett Shale currently represent our core business, we intend to diversify our business into other sectors of the midstream industry such as crude oil gathering, storage and transportation, through both greenfield development projects and acquisitions, and into other geographic regions. We and our sponsors are frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energy infrastructure assets. Working together with our sponsors, we intend to continue to evaluate opportunities to acquire or develop other midstream energy infrastructure assets that complement our existing business and allow us to leverage our asset base and our management team's development and industry expertise.

Competitive Strengths

        We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:

•

Strategically located assets in core areas of prolific unconventional basins supported by existing partnerships with large producers to provide midstream services for their development projects.  Our midstream energy infrastructure assets are strategically positioned within the core areas of two established unconventional resource plays. The formations in the basins served by our assets have relatively low drilling and completion costs. We believe that producers will continue their drilling and completion activities in the core areas of unconventional natural gas shale basins even if natural gas prices do not increase significantly from current levels because the return economics associated with core-area wells remain favorable in lower pricing environments compared to more marginal areas of production. We believe that continued drilling activity in these basins positions us to pursue attractive growth opportunities by further developing and optimizing our systems and by developing or acquiring complementary systems within our geographic areas of operation.



•

Grand River system. The Grand River system is located in the Piceance Basin and currently serves the established liquids-rich Mesaverde formation and is optimally located for expansion to serve the emerging Mancos and Niobrara Shale formations. In the Piceance Basin, production from the emerging Mancos and Niobrara Shale formations has only recently begun, as producers have started drilling wells in these formations in the last two years. We are constructing a new medium-pressure gathering system to service anticipated higher pressure gas production from the emerging Mancos and Niobrara Shale formations.

126

---

•

DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, Texas, currently the largest natural gas producing county in the state. We consider this area to be the "core of the core" of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. We believe that the AMIs underpinning our system are substantially undeveloped compared to other areas in the Barnett Shale due to the lack of historical gathering infrastructure in this area and limited associated drilling activity. We believe that our AMIs and our system footprint provide us with a competitive advantage to add additional producers and incremental volumes in this growing area of the Barnett Shale at a competitive capital cost.



•

Fee-based revenues underpinned by long-term contracts.  A substantial majority of our revenue for the year ended December 31, 2011 was generated under long-term, fee-based gas gathering agreements. Several of our customers are among the largest producers in each of our areas of operation. In the Piceance Basin, we have a 25-year AMI covering approximately 187,000 acres and a 15-year minimum volume commitment with Encana for approximately 1.5 Tcf. Together with our other gas gathering agreements with producers in the Piceance Basin, we have AMIs covering approximately 230,000 acres, average minimum volume commitments of 498 MMcf/d through 2020 and total volume commitments of almost 2.1 Tcf in the Piceance Basin through 2026. Our gas gathering agreements with our Barnett Shale customers have AMIs covering approximately 100,000 acres in the high-growth core area of the Barnett Shale and minimum volume commitments of approximately 463 Bcf through 2020. We believe that having long-term, fee based gas gathering agreements with minimal direct commodity price exposure enhances the predictability of our performance.



•

Capital structure and financial flexibility.  At the closing of this offering, we expect to have approximately $     million of borrowing capacity available to us under our amended and restated revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital will provide us with the requisite financial flexibility to execute our growth and expansion strategy.



•

Experienced management team with proven record of asset acquisition, construction, development, operation and integration expertise. Our executive management team has an average of 16 years of energy experience and a proven track record of identifying and consummating significant acquisitions in addition to partnering with major producers to construct and develop midstream infrastructure. As demonstrated by our current business, our management team has demonstrated particular expertise in constructing new—and developing and optimizing underutilized—midstream assets, which are key elements of our growth strategy. We employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream energy projects.



•

Relationships with large and committed financial sponsors.  Our sponsors, Energy Capital Partners and GE Energy Financial Services, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality midstream energy assets. Energy Capital Partners has indicated that it intends to use us as its primary platform for the acquisition, construction and development of future midstream infrastructure assets; however, it is not obligated to do so. While there are no assurances that we will benefit from our relationship with our sponsors, we believe our relationship with both of our sponsors will be a competitive advantage, as they both bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will benefit us as we seek to grow our business. In addition, we believe that Energy Capital Partners and GE Energy Financial Services, as the indirect owners of our general partner interest, all of our incentive distribution rights and a        % limited partner interest in us, will be motivated to promote and support the successful execution of our business strategies.

127

---

Our Sponsors

        We were formed in 2009 by members of our management and Energy Capital Partners, which together with its affiliated funds, is a private equity firm with over $7.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us. To date, Energy Capital Partners has formed 21 investment platforms across its funds with investments in the power generation, electric transmission, midstream natural gas and renewable sectors of the energy industry. In August 2011, Energy Capital Partners sold an interest in Summit Investments to GE Energy Financial Services. GE Energy Financial Services invests globally in essential, long-lived and capital-intensive energy assets. To date, GE Energy Financial Services has invested over $20 billion in energy investments worldwide, of which approximately $2.4 billion has been committed to midstream-related portfolio companies.

Our Assets

        Our assets currently consist of two natural gas gathering systems, the Grand River system in western Colorado and the DFW Midstream system in north-central Texas. These systems are discussed in more detail below.

Grand River System

        The following table provides information regarding our Grand River system as of May 31, 2012.

128

---

        In October 2011, we acquired the Grand River system from Encana for $590 million. The Grand River system is primarily located in Garfield County, Colorado, the largest natural gas producing county in Colorado, and comprises approximately 276 miles of 3 inch to 24 inch diameter pipeline and approximately 97,500 horsepower of compression. The Grand River system gathers natural gas from the Mesaverde, Mancos and Niobrara Shale formations located within the Piceance Basin. All of the natural gas volumes gathered on the Grand River system are discharged to third-party pipelines that deliver to Enterprise Products Partners L.P.'s 1.7 Bcf/d processing facility located in Meeker, Colorado.

        The Grand River system has total throughput capacity of 885 MMcf/d and for the quarter ended March 31, 2012 gathered an average of approximately 593 MMcf/d. The system gathers production from the Mamm Creek, South Parachute and Orchard fields in the area around Rifle, Colorado. The Grand River system is underpinned by long-term, fee-based gas gathering agreements with Encana, WPX Energy, Bill Barrett Corporation and Antero Resources that include minimum volume commitments with original terms ranging from 10 to 15 years and AMIs with original terms ranging from 10 years to 25 years. As of March 31, 2012, these gas gathering agreements had remaining minimum volume commitments totaling approximately 2.1 Tcf over the next 15 years, an average of approximately 498 MMcf/d through 2020, and AMIs covering approximately 230,000 acres for terms of up to 25 years. Our customers do not have leases that currently cover our entire AMIs in the Piceance Basin but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the Grand River system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

        The Grand River system is currently a low-pressure gathering system that was originally designed to gather natural gas produced from traditional vertical wells focused on the shallower, higher-Btu Mesaverde formation. Our largest Grand River customer, Encana, currently has approximately 1,720 wells on approximately 375 pad sites connected to our existing low-pressure gathering system. We also receive natural gas from other producer customers at nine central receipt points on the Grand River

129

---

system. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize the existing available throughput capacity.

        In connection with our acquisition of the Grand River system, we entered into a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

DFW Midstream System

        The following table provides information regarding our DFW Midstream system as of May 31, 2012.

        The DFW Midstream system is located within the primarily urban environment of southeastern Tarrant County, Texas, which resides within the Fort Worth Basin and includes the Barnett Shale geologic formation. We consider this area to be the "core of the core" of the Barnett, which, according to the Texas Railroad Commission, contains the most prolific wells, including the two largest and four of the ten largest wells drilled to date, in the Barnett Shale based on peak month daily average

130

---

production rates. The DFW Midstream system, which has been under construction since 2008, includes gathering lines ranging from 8 inches to 30 inches in diameter and is located along existing electric transmission corridors and under both private and municipal property. The system currently has five primary interconnections with third-party, intrastate pipelines that enable us to connect our customers with downstream pipelines serving the established Waha, Carthage and Perryville natural gas market hubs in Texas and Louisiana.

        Our development of the DFW Midstream system is underpinned by seven long-term, fee-based gas gathering agreements with Chesapeake, TOTAL, Carrizo, Atlas Energy, EOG, Exxon Mobil and Vantage. As of March 31, 2012, these gas gathering agreements have remaining minimum volume commitments totaling approximately 463 Bcf and average, through 2020, approximately 145 MMcf/d. In addition, these gas gathering agreements have AMIs that cover approximately 100,000 acres through 2030. Our customers do not have leases that currently cover our entire AMIs in the Barnett Shale but, to the extent our customers lease additional acreage in the future within those AMIs, natural gas produced by our customers from that leased acreage will be gathered by the DFW Midstream system. For a more detailed description of these gas gathering agreements, please read "—Gas Gathering Agreements."

        We have owned and operated the DFW Midstream system since 2009, when we acquired it from Energy Future Holdings and concurrently acquired certain complimentary pipeline and other related gathering system assets from Chesapeake. We simultaneously entered into a long-term gas gathering agreement with Chesapeake as our anchor customer that included a 20-year AMI covering approximately 95,000 acres and a 10-year minimum volume commitment totaling approximately 450 Bcf. At the time of the acquisition, the DFW Midstream system had average throughput of approximately 10 MMcf/d and had approximately 17 miles of pipeline and 2,500 horsepower of installed electric-drive compression in service.

        Since the acquisition, we have expanded the DFW Midstream system by adding approximately 93 miles of additional pipeline and 47,600 horsepower of electric-drive compression. For the quarter ended March 31, 2012, the DFW Midstream system had average throughput of approximately 315 MMcf/d. We continue to develop the DFW Midstream system to extend our gathering reach, diversify our customer base, increase our receipt points and maximize throughput on the system. In 2012, we intend to continue to connect additional pad sites located within our AMIs and expand the throughput capacity from 410 MMcf/d to over 450 MMcf/d by installing additional electric-drive compression. The system will include approximately 120 miles of low- and high-pressure gathering lines and 56,100 horsepower of electric-drive compression. As of May 31, 2012, approximately 310 wells on 62 pad sites were connected to the DFW Midstream system and 34 additional wells were in various stages of completion, 29 of which are on existing pad sites that we currently serve and 5 of which are on pad sites to which we intend to connect.

        While there has been substantial development of the broader 24-county Barnett Shale over the past decade, southeastern Tarrant County, which is located in the core area of the Barnett Shale, has been largely undeveloped due to the urban landscape and the absence of natural gas gathering infrastructure. The DFW Midstream system, which is primarily located in southeast Tarrant County, has addressed the historical lack of gathering infrastructure and currently provides producers in the area with a safe, efficient and reliable solution to deliver their natural gas to market. Tarrant County, which is currently the largest natural gas producing county in Texas, experienced an increase in natural gas production from 1.6 Bcf/d in October 2009 to 2.0 Bcf/d in October 2011. Over this same period, throughput on the DFW Midstream system increased from approximately 10 MMcf/d to approximately 380 MMcf/d, which accounted for approximately 90% of Tarrant County's increased natural gas production.

        We believe the production profile of wells drilled within our AMIs, which includes the two largest wells ever drilled in the Barnett Shale, will continue to attract drilling activity over the long term as

131

---

producers become more selective in their drilling locations in order to maximize their returns. We also believe that the acreage dedicated to the DFW Midstream system is substantially undeveloped as evidenced by our 100,000 acre gathering footprint and our customers' desire to reduce well spacing below 50 acres to maximize recoverable reserves. We believe our strategic location in the core of the core of the Barnett Shale provides us with a competitive advantage to add incremental throughput with limited additional investment capital due to the anticipated future, high-density, infill drilling from our customers on connected pad sites and nearby pad sites that have yet to be connected. This high-density, infill drilling, is magnified in our area given the urban landscape and the desire of our producer customers to minimize their surface footprint.

Gas Gathering Agreements

        We derive revenue primarily from long-term, fee-based, gas gathering agreements, or GGAs, with some of the largest and most active producers in our areas of operation. The following describes the material provisions included in the majority of our firm gas gathering agreements with our significant customers, including our natural gas gathering agreements with Chesapeake, Encana, Carrizo Oil and Gas and WPX Energy.

AMIs and Contract Terms

        Our gas gathering agreements contain AMIs. The AMIs generally have original terms that range from 10 years to 25 years and require that any production by our customers within the AMIs will be shipped on gathering systems. Under certain of our GGAs, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. If we choose to forego a discretionary opportunity presented by the customer, such as constructing a lateral to an additional pad site, or constructing additional pipeline infrastructure or related assets in connection with a customer's expansion of its drilling operations, the customer may, in certain circumstances, construct the additional infrastructure and sell it to us at a price equal to their cost plus an applicable margin, or, in some cases, release the relevant acreage dedication from the AMI.

Minimum Volume Commitments

        Our gas gathering agreements contain minimum volume commitments, or MVCs, pursuant to which our customers guarantee to ship a minimum volume of natural gas on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. The original terms of the MVCs range from 7 to 15 years. In addition, certain of our customers have an aggregate MVC, which is a total amount of natural gas that the customer must transport on our gathering systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.

        If a customer's actual throughput volumes are less than its MVC for the applicable period, it must make a shortfall payment to us at the end of that contract month or year, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable period, however, many of our GGAs contain provisions that can operate to reduce or delay the cash flows that we expect to receive from our MVCs. These provisions include the following:

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual MVC (depending on the terms of the specific gas

132

---

gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding months or years (as applicable).

•

To the extent that a customer's throughput volumes exceed its MVC in the applicable period, it is entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. For example, one of our DFW Midstream customers has a contracted MVC term from October 2010 through September 2017. However, this customer has regularly shipped excess natural gas on our DFW Midstream system relative to its MVC. Assuming its throughput rate remains at this level, we estimate that it will satisfy the requirements of its aggregate MVC by the end of 2012, thereby reducing the period for which its MVC applies from eight years to less than three years. As a result of this mechanism, the weighted average remaining period for which our MVCs apply is less than the weighted average of the original stated terms of our MVCs.



•

To the extent that a customer's throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a "bank" of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall payment owed in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular GGA.

Fuel Retainage Fees and Cost Pass-Throughs

        Our GGAs on our DFW Midstream system allow us to retain a small fixed percentage of the natural gas that we receive at the receipt points to offset the costs we incur to operate our electric-drive compressors. On average, we retain nominal amounts of the natural gas received at the receipt points on the DFW Midstream system. Our GGAs on our Grand River system allow us to (i) charge our customers for the electricity costs we incur to operate our electric-drive compressors and (ii) utilize physical gas on the Grand River system to operate our gas-fired compressors.

Pressure Variance Penalties

        Our GGAs require us to maintain certain specified operating pressures on our gathering systems, both on a system-wide basis and with respect to each receipt point. We are also required to maintain certain minimum operating pressures at certain of our compressor stations. If we fail to maintain our required system and receipt point operating pressures, we can be subject to penalties in the form of substantial reductions in our gathering fees (subject, in certain circumstances, to force majeure relief). These reductions generally range from 25% to 75%, depending on the duration of the pressure variance. With respect to compressor station pressure variances, we are subject to penalties in the form of loss of our fuel retainage fees and our ability to pass our electricity costs on to the customer for a period of time, depending on the duration of the pressure variance. With respect to system and receipt point pressure variances that persist for extended periods of time (generally exceeding four months in any consecutive twelve month period), our customers are entitled to additional remedies, including:

•

a 100% reduction in gathering fees applicable to future shipments until the end of the first month following the resolution of the pressure variance; and



•

the ability to release all or a portion of the customer's future gas production from the GGA.

Competition

        The natural gas gathering, compression and transportation business is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to end-use markets, location, available capacity, capital expenditures and

133

---

fuel efficiencies. Our principal competitors in the Fort Worth Basin are Chesapeake Midstream Partners, L.P., Crestwood Midstream Partners LP and Energy Transfer Partners, L.P. Our principal competitors in the Piceance Basin are Williams Partners L.P., Energy Transfer Partners, L.P. and Enterprise Products Partners L.P.

        In the future, we may face competition for production drilled outside of our AMIs and on attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition.

Safety and Maintenance

        We are subject to regulation by DOT under the Natural Gas Pipeline Safety Act of 1968, as amended, also known as the NGPSA, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas pipeline facilities. In the Pipeline Safety Act of 1992, also known as the PSA, Congress expanded DOT's regulatory authority to include "regulated gathering lines" that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002, also known as the PSIA, and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, also known as the PIPES Act, established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.

        DOT has delegated the implementation of safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations, similar to existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW gathering system is located, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways. While the majority of our pipelines meet the DOT definition of gathering lines and are thus exempt from PHMSA's integrity management requirements, we also operate three pipelines in the Dallas-Fort Worth area that are subject to the integrity management requirements. The regulations require operators, including us, to:

•

perform ongoing assessments of pipeline integrity;



•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;



•

maintain processes for data collection, integration and analysis;



•

repair and remediate pipelines as necessary; and



•

implement preventive and mitigating actions.

        While repairs, remediation or preventative or mitigation measures resulting from integrity management inspections could obligate us to make material expenditures, we do not anticipate such an outcome because our pipelines are relatively new.

        Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published an advanced notice of proposed

134

---

rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and extend the integrity management requirements to certain gathering lines. Extending the integrity management requirements to our gathering lines would impose additional obligations on us and could add material costs to our operations.

        We believe that we are in compliance with existing safety laws and regulations and we cannot predict the outcome of new regulatory initiatives; however, increased penalties for safety violations and potential regulatory changes could have a material effect on our operations, operating and maintenance expenses, and revenues.

        We are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act, or the OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to the OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We are also subject to EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety, community right to know laws, and the security of our facilities.

Regulation of the Oil and Natural Gas Industries

General

        Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at uncontrolled market prices; however, regulation of gathering and transportation services may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services. FERC and FTC are also authorized to prevent and sanction market manipulation in natural gas markets and petroleum markets, respectively. State and municipal regulations may apply to the production and gathering of natural gas, the construction and operation of natural gas and crude oil facilities, and the rates and practices of gathering systems and intrastate pipelines.

Regulation of Oil and Natural Gas Exploration, Production and Sales

        Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. Either

135

---

Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.

        Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of resources, including provisions for the unitization or pooling of producing properties, the establishment of maximum rates of production from wells, and the regulation of spacing of wells. These state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas for gathering by us.

Regulation of the Gathering and Transportation of Natural Gas

        We believe that our gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA, although we are subject to FERC's anti-market manipulation regulations (see Anti-Market Manipulation Rules below). The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines has been the subject of extensive litigation and may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC or the courts. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

        Our gathering of natural gas is also affected by the availability, terms and cost of downstream transportation services. The rates and terms for access to pipeline transportation services are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing systems have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. FERC's regulations require, among other things, that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of FERC's initiatives has been to eliminate the interstate pipelines' traditional role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a non-discriminatory basis. The rates for such transportation and storage services are subject to FERC ratemaking authority, and FERC exercises its authority by applying cost-of-service principles, allowing for the negotiation of rates where there is a cost-based alternative rate or granting market-based rates in certain circumstances, typically with respect to storage services.

        Natural gas production, gathering and transportation may be subject to state and local regulations that may change from time to time. Our construction of new gathering facilities and expansion of existing gathering facilities may be subject to state and local regulation, including approval and permit requirements. Regulation of our operations may cause us to incur additional operating costs or limit the quantities of gas we may gather. In addition, state ratable take statutes and regulations generally require us to take natural gas production that may be tendered to us for handling without undue discrimination. These statutes are designed to prohibit discrimination in favor of one source of supply over another source of supply and they restrict our right to decide whose production we gather.

136

---

        Gathering systems and pipelines that operate only in a single state may be subject to regulation by state regulatory authorities with respect to safety (under a federal certification) and rates and practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we have filed a tariff with the Texas Railroad Commission to establish rates and terms of service for our DFW operations. We have not been required to file a tariff in Colorado for our Grand River assets. Both of these states have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint.

        Intrastate pipelines that provide interstate transportation service are regulated by FERC under Section 311 of the NGPA as to rates and other terms and conditions of service with respect to interstate gas shipments, unless an exemption from such regulation applies (such as for gathering lines). We believe that our pipelines are gathering systems that are therefore exempt from Section 311 requirements.

        Changes in federal, state, or local law or policy may affect us either directly or indirectly. While we cannot predict what further action legislators or regulators will take, we do not believe that any such action taken will affect us differently, in any material way, than other midstream companies with which we compete.

Regulation of Crude Oil and NGL Transportation Rates

        In a number of instances the ability to transport and sell crude oil and NGLs is dependent on pipelines whose rates and other terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992, state regulatory jurisdiction under state statutes, or both. Interstate transportation rates for crude oil and NGLs, among other liquid commodities, are regulated by FERC, and, in general, these rates must be cost-based or based on rates in effect in 1992, although FERC has established an indexing system for such transportation rates which allows pipelines to take an annual inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. FERC has also established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances.

        In other instances involving intrastate-only transportation of crude oil, NGLs and other products, the ability to transport and sell such commodities is dependent on transportation by pipelines at rates, and on other terms and conditions of service that are subject to regulation by state regulatory authorities. Such pipelines may be subject to state regulation with respect to safety (under a federal certification) and rates and other practices, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of intrastate liquids pipelines varies from state to state. Many states operate on a complaint-based system and state authorities have generally not initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.

Anti-Market Manipulation Rules

        We are subject to the anti-market manipulation provisions in the NGA, as amended by EPAct 2005, which authorize FERC to impose fines of up to one million dollars ($1,000,000) per day per violation of the NGA or its implementing regulations. In addition, FTC holds statutory authority under the EISA to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to one million dollars ($1,000,000) per day per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations for the commodity and

137

---

futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Failure to comply with such market rules, regulations and requirements could have a material adverse effect on our business, results of operations, and financial condition.

Environmental Matters

General

        Our operation of pipelines and other facilities for the gathering, compressing and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•

requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;



•

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;



•

delaying system modification or upgrades during permit reviews;



•

requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and



•

enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

        Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

        We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion

138

---

of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

        Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

        We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as "hazardous wastes" and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

        We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Act (OPA)

        In 1991, the EPA adopted regulations under the OPA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan, or SPCC, for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most

139

---

importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

        Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

        Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA must finalize the proposed amendments by December 14, 2012. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. Compliance with the final rule currently is required by October 2013. We are continuing our evaluation of the cost impacts of the final rule and proposed amendments.

        On June 28, 2011, the EPA issued a final rule, effective August 29, 2011 modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule is not required until at least 2013. On May 22, 2012, the EPA proposed minor amendments which must be finalized by December 14, 2012. We are currently evaluating the impact that this final rule and proposed amendments will have on our operations.

        On April 17, 2012, the EPA finalized rules that establish new air emission control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or 60 days after the final rule is published in

140

---

the Federal Register. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, the EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, which may impact our customers. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. These requirements may result in increased operating costs for producers who drill near our pipelines, which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Business—Environmental Matters—Hydraulic Fracturing."

        These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unit holders.

Water Discharges

        The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

Hydraulic Fracturing

        The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities, and we believe that our facilities will not be materially adversely affected by such requirements. However, a portion of our customers' natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. We do not engage in any hydraulic fracturing activities although many of our customers do. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and

141

---

require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act's Underground Injection Control Program to require disclosure of chemicals used in the hydraulic fracturing process. Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between the latter part of 2012 and 2014. In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities. On May 4, 2012, the BLM issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.

        Several states, including states in which our customers do business, such as Texas and Colorado, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. We cannot predict whether any other legislation will be enacted in the future and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenue and results of operations. For additional information about hydraulic fracturing and related environmental matters, please read "Risk Factors—Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues."

Endangered Species

        The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas.

National Environmental Policy Act

        The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

        Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to the scientific studies, international negotiations to address climate

142

---

change have occurred. The United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent by 2020 compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

        In the United States, legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a "cap and trade" program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an "air pollutant," and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act.

        In addition, in September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. We are required to report under these rules for certain of our assets. The EPA continues to consider additional climate change requirements, such as the March 2011 proposed rules regarding future coal-fired power plants. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. However, due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact that related developments will have on us.

        Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

        The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Anti-terrorism Measures

        The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements,

143

---

including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

Title to Properties and Rights-of-Way

        Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to perpetual easements between us and the underlying fee owner, or permits with governmental authorities. Our Predecessor leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the exception of certain permits with governmental entities that have been applied for, but not yet issued.

Employees

        We do not have any employees. The officers of our general partner will manage our operations and activities. As of March 31, 2012, Summit Midstream Partners, LLC employed 73 people who provide direct, full-time support to our operations, including 19 field-level employees we hired from Encana in connection with our acquisition of the Grand River system. Subsequent to the closing of this offering, all of the employees required to conduct and support our operations will be employed by our general partner or its affiliates. None of these employees are covered by collective bargaining agreements, and our general partner considers its employee relations to be good.

Legal Proceedings

        Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

144

---

MANAGEMENT

Management of Summit Midstream Partners, LP

        We are managed by the directors and executive officers of our general partner, Summit Midstream GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Summit Investments owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Director Independence

        Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed limited partnership like us to have, and we do not intend to have, a majority of independent directors on the board of directors of our general partner.

Committees of the Board of Directors

        The board of directors of our general partner will have an audit committee, or the Audit Committee, and a conflicts committee, or the Conflicts Committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

        Our general partner will have an Audit Committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. Our general partner will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of the Audit Committee. Those rules permit our general partner to have an audit committee that has one independent member upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. The Audit Committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the Audit Committee.

Conflicts Committee

        At least two members of the board of directors of our general partner will serve on our Conflicts Committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The Conflicts Committee will determine if the resolution of the conflict of interest is fair and reasonable to us. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, employees of any of its affiliates, may not hold any ownership interest in our general partner or us and our

145

---

subsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the board of directors of our general partner including any member of the Conflicts Committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been taken or omitted in good faith.

Directors and Executive Officers

        Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.

        Steven J. Newby has been the President and Chief Executive Officer of our general partner since May 2012. Mr. Newby was a founding member of Summit Midstream Partners, LLC and has been the President and Chief Executive Officer of Summit Midstream Partners, LLC since its formation in September 2009. Mr. Newby's background includes over 15 years of oil and gas experience with a focus on the midstream sector of the energy industry. Mr. Newby was a founding member of SunTrust Bank's Corporate Energy industry specialty group and ultimately became a Managing Director and Head of the Project Finance Group within SunTrust's Capital Markets division. In 2007, Mr. Newby joined ING Investment Management to manage a $300 million proprietary fund focused on the private and public investment in the energy infrastructure space. Mr. Newby is a graduate of the University of North Carolina at Chapel Hill with a B.S. in Business Administration with a concentration in Finance.

        Matthew S. Harrison has been the Senior Vice President and Chief Financial Officer of our general partner since May 2012. Prior to joining our general partner, Mr. Harrison was the Senior Vice President and Chief Financial Officer of Summit Midstream Partners, LLC since September 2011. Mr. Harrison's background includes over 12 years of energy and finance experience. Mr. Harrison joined Summit Midstream Partners, LLC from Hiland Partners, LP, where he served as Executive Vice President and Chief Financial Officer, Secretary and Director from February 2008 to September 2011. Prior to joining Hiland, Mr. Harrison was a Director in the Energy & Power Merger & Acquisitions group at Wachovia Capital Markets from October 2007 to February 2008 and a Director in the

146

---

Mergers & Acquisitions group at A.G. Edwards & Sons, Inc. from July 1999 to October 2007. Mr. Harrison is a Certified Public Accountant and was a Senior Accountant for PricewaterhouseCoopers for five years. Mr. Harrison received an MBA from Northwestern University—Kellogg Graduate School of Management in 1999 and a B.S. in Accounting from the University of Tennessee in 1992.

        Brad N. Graves has been the Senior Vice President of Corporate Development of our general partner since May 2012. Prior to joining our general partner, Mr. Graves was the Senior Vice President of Corporate Development of Summit Midstream Partners, LLC since April 2010. He was previously a Partner with Crestwood Midstream Partners, LLC from February 2008 until March 2010. Mr. Graves has served as Executive Vice President—Business Development of Genesis Energy, LP (AMEX: GEL) from August 2006 until November 2007. He also served as Vice President—Offshore Commercial for Enterprise Products Partners L.P. (NYSE: EPD) from 2004 until August 2006. Prior to 2004, Mr. Graves served in a variety of commercial roles at EPD and GulfTerra Energy Partners, LP (NYSE: GTM), prior to its merger with EPD. In his roles with EPD and GTM, Mr. Graves participated in numerous greenfield projects developed in the Gulf of Mexico. Mr. Graves earned a B.B.A. in Accounting from Texas A&M University in 1989 and an MBA in Marketing and Finance from the University of Saint Thomas in 1994.

        Rene L. Casadaban has been the Senior Vice President of Engineering, Construction, and Operations of our general partner since May 2012. Prior to joining our general partner, Mr. Casadaban was the Senior Vice President of Engineering, Construction and Operations of Summit Midstream Partners, LLC from November 2010 to April 2012. Mr. Casadaban has 20 years of project management experience for onshore, offshore and deepwater pipeline systems. Prior to joining Summit Midstream Partners, LLC, Mr. Casadaban worked for Enterprise Products Partners L.P. from 2006 to 2010 as the Director for Deepwater Development of floating production platforms and offshore pipelines. Mr. Casadaban has also served as an independent consultant to ExxonMobil and GulfTerra for Gulf of Mexico and international pipeline projects. At Land & Marine, Mr. Casadaban was responsible for managing domestic and international pipeline river crossings and beach approaches by horizontal directional drilling. Mr. Casadaban is a graduate of Auburn University with a B.S. in Building Construction.

        Brock M. Degeyter has been the Senior Vice President and General Counsel of our general partner since May 2012. Mr. Degeyter joined Summit Midstream Partners, LLC in January 2012 as Senior Vice President and General Counsel. Mr. Degeyter's background includes over ten years of energy, finance and business law experience. Prior to joining our general partner, Mr. Degeyter worked in the corporate legal department for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director of Corporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with the firm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed to practice law in the states of Texas and Louisiana. Mr. Degeyter received a B.A. in Political Science from Louisiana State University and a J.D. from Loyola University College of Law in New Orleans.

        Thomas K. Lane has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Lane has been a partner of Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton College and an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation

147

---

with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

        Andrew F. Makk has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Makk has been a Principal at Energy Capital Partners since 2005. Prior to joining Energy Capital Partners, he was a co-founder of a privately held energy company from 2002 to 2005, which built a portfolio of energy projects in Europe on behalf of a private equity fund through the acquisition of existing projects and development of new projects. Prior to 2002, Mr. Makk spent nine years with Enron International in various power and LNG asset development roles and became Head of Asset Development for Enron Europe in London. He received a B.S.M. in Finance from Tulane University and an MBA from the Fuqua School of Business at Duke University. Mr. Makk was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

        Curtis A. Morgan has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls our general partner. Mr. Morgan has served as the President and Chief Executive Officer of EquiPower Resources Corp. since May 2010. Prior to joining EquiPower Resources Corp., he served as an Operating Partner of Energy Capital Partners from May 2009 to May 2010. Prior to joining Energy Capital Partners, he served as President and Chief Executive Officer of FirstLight Power Enterprises from November 2006 to April 2009. Mr. Morgan has also held leadership positions at NRG Energy, Mirant Corporation and Reliant Energy. Mr. Morgan received a B.A. in Accounting from Western Illinois University and an MBA in Finance and Economics from the University of Chicago. He is a Certified Public Accountant. We believe that Mr. Morgan's extensive executive, financial and operational experience bring important and necessary skills to the board of directors.

        Tyson R. Yates has served as a director of our general partner since May 2012 and was appointed to the board in connection with his affiliation with GE Energy Financial Services, Inc. Mr. Yates currently serves as Managing Director of the Midstream portfolio group at GE Energy Financial Services, a position he assumed in March 2007. Over the past 12 years, Mr. Yates has held a variety of positions at GE Energy Financial Services, including Senior Vice President in the Midstream sector investment group. In his current position, Mr. Yates serves on a number of boards that currently include Southern Star Central Corp., a regulated interstate natural gas pipeline system headquartered in Kentucky, SourceGas Holdings Inc., a local gas distribution company headquartered in Colorado, and Phoenix Park Gas Processors Ltd., a natural gas processing plant in Trinidad. Prior to joining GE Energy Financial Services, Mr. Yates held the position of Senior Manager in the Special Acquisition Services and Audit practice at Deloitte & Touche LLP. Mr. Yates has a B.S. in Accounting from the University of Florida and is a Certified Public Accountant. We believe that Mr. Yates's extensive executive and financial experience bring important and necessary skills to the board of directors.

Executive Compensation

        The following describes the material components of our compensation policies with respect to the following individuals, who are our general partner's executive officers and referred to as the "named executive officers":

•

Steven J. Newby, President and Chief Executive Officer;



•

Matthew S. Harrison, Senior Vice President and Chief Financial Officer; and



•

Rene L. Casadaban, Senior Vice President, Engineering, Construction and Operations.

148

---

Summary Compensation Table for 2011

        The following table sets forth certain information with respect to the compensation paid to our named executive officers for the year ended December 31, 2011.

Narrative Disclosure to Summary Compensation Table

Elements of Compensation

        The primary elements of compensation for the named executive officers are base salary, annual incentive compensation and long-term equity-based compensation awards. The named executive officers also receive certain retirement, health, welfare and additional benefits as described below.

        Base Salary.    Base salaries for our named executive officers have generally been set at levels deemed necessary to attract and retain individuals with superior talent. None of our named executive officers received any base salary adjustments or increases during 2011, other than cost of living increases provided to all of our employees. However, effective March 2012, generally in preparation for this offering, base salary increases were approved for each named executive officer other than

149

---

Mr. Harrison, whose base salary was set in September 2011 upon his commencement of employment with us. The base salaries of our named executive officers before and after the increase, as applicable, are set forth in the following table:

        Annual Incentive Compensation.    For 2011, Messrs. Newby and Harrison had target bonuses of $223,500 and $221,250, respectively, or 75% of their base salaries. Our board of directors used its discretion to award both executives bonuses slightly in excess of their targets because, although we underperformed on our Adjusted EBITDA targets, we successfully completed our acquisition of the Grand River system under their leadership. Pursuant to Mr. Harrison's employment agreement, his bonus was not prorated, despite his September hire date.

        Mr. Casadaban's target incentive compensation was 75% of his base salary, or $150,000. Quantitative factors determined 70% of Mr. Casadaban's incentive compensation and qualitative factors determined 30%. Quantitative factors considered in determining the bonus included achievement of certain Adjusted EBITDA thresholds, construction goals and operational and safety goals. Although we underperformed on our Adjusted EBITDA targets, we achieved near target on our construction goals and significantly above target on our operational goals. As a result, Mr. Casadaban was awarded $79,800 or 76% of target for the portion of his bonus based on quantitative factors, and $75,200 or 167% of target for the portion of his bonus based on qualitative factors, primarily due to his significant contributions to the closing of the acquisition of the Grand River system. In total, Mr. Casadaban was awarded approximately 103% of his target incentive compensation for 2011.

        Long-Term Equity-Based Compensation Awards.    The named executive officers were each granted equity-based compensation awards in the form of interests ("upstairs profits interests") in a collective partnership vehicle, referred to in this prospectus as Summit Management, through which our named executive officers indirectly hold Class B percentage interests in Summit Investments ("downstairs profits interests"). The downstairs profits interests represent indirect interests in Summit Investments' future profits, and allow Summit Management to share in distributions by Summit Investments only after Summit Investments' Class A Members have received distributions in an amount equal to the sum of the fair market value of the downstairs profits interests at the time of grant plus any capital contributions made subsequent to the date of grant. The upstairs profits interests entitle the named executive officers to receive from Summit Management the proceeds of any distributions received by Summit Management from Summit Investments in respect of the corresponding downstairs profits interests, subject to the terms set forth in the partnership agreement of Summit Management. The upstairs profits interests are referred to in this prospectus as the Pre-IPO Equity Awards.

        The Pre-IPO Equity Awards were granted subject to a five-year time-based vesting schedule, subject to the named executive officer's continued employment through the applicable vesting date. The Pre-IPO Equity Awards are eligible for an additional one year of vesting in the event the named executive officer's employment is involuntarily terminated by the applicable employer without cause, or is terminated due to the named executive officer's death or disability, or, in the case of Mr. Newby, is

150

---

terminated by him due to his resignation with good reason (as defined in the employment agreements, described below). The Pre-IPO Equity Awards are eligible for full 100% accelerated vesting if the named executive officer's employment is involuntarily terminated without cause or, in the case of Mr. Newby, is terminated by the named executive officer due to his resignation with good reason, within the 12 months after a change in control of Summit Investments. In the event of a named executive officer's termination of employment for any other reason, the named executive officer's Pre-IPO Equity Awards will be forfeited.

        Pursuant to the applicable partnership agreements, the vested downstairs profits interests may be repurchased by the applicable employer or Energy Capital Partners in certain circumstances. In the event of the termination of a named executive officer's employment due to death, disability, termination by the applicable employer without cause or, in the case of Mr. Newby, resignation with good reason or non-extension of the term of the employment agreement, the repurchase price will be equal to the value of the downstairs profits interests in a hypothetical liquidation of the applicable employer pursuant to the rights and preferences set forth in the partnership agreement, assuming all assets were sold for their fair market value. In the event of termination for cause, resignation (in the case of Mr. Newby, without good reason) or a purported transfer by the named executive officer or the management company in violation of the partnership agreement, the repurchase price will equal $0. In the event of a repurchase of the downstairs profits interests, the corresponding upstairs profits interests will be repurchased from the named executive officer by Summit Management for the same repurchase price.

        Going forward, we expect that equity-based incentive awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process. In anticipation of this offering, we intend to adopt a new long-term equity incentive plan, which is discussed in more detail under "2012 Long-Term Incentive Plan" below.

        Retirement, Health and Welfare and Additional Benefits.    The named executive officers are eligible to participate in such employee benefit plans and programs as we may from time to time offer to our employees, subject to the terms and eligibility requirements of those plans. The named executive officers are eligible to participate in a tax-qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2011, we made a fully vested contribution on behalf of each of the 401(k) plan's participants equal to 3% of such participant's salary for the year.

Outstanding Equity Awards at December 31, 2011

        The following table provides information regarding the Pre-IPO Equity Awards held by the named executive officers as of December 31, 2011.

151

---

Employment and Severance Arrangements

        We have entered into employment agreements with Steven J. Newby (dated September 3, 2009), and Matthew S. Harrison (dated September 15, 2011). Rene Casadaban is not a party to an employment agreement.

        The current term of Mr. Newby's employment agreement expires on August 31, 2012. Mr. Harrison's employment agreement has an initial term of two years, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 90 days prior to the expiration of the then-applicable term. Each employment agreement provided for the named executive officer's initial base salary and a performance-based bonus ranging from 0% to 150% of base salary, with a target of 75% of base salary. Mr. Harrison's employment agreement also provides for a $25,000 cash signing bonus, reimbursement for up to $60,000 in relocation expenses incurred in relocating to Atlanta, Georgia, and reimbursement for tax preparation expenses in the amount of $10,000 per year. No such reimbursements were yet paid to Mr. Harrison in 2011.

        Each employment agreement provides for a cash severance payment upon a termination by us without cause or by the named executive officer for good reason, which is defined generally as the named executive officer's termination of employment within two years after the occurrence of (i) a material diminution in the named executive officer's authority, duties or responsibilities, (ii) a material diminution in the named executive officer's base compensation, (iii) a material change in the geographic location at which the named executive officer must perform his services under the agreement or (iv) any other action or inaction that constitutes a material breach of the employment agreement by us. Each employment agreement provides that the named executive officer's severance payment will be equal to the sum of his annual base salary and the annual bonus payable in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days in the period beginning on the date of termination and ending on the later of (a) the last day of the then-applicable term of the employment agreement and (b) the first anniversary of the date of termination (the "severance period") and the denominator of which is 365. The severance payment is payable in equal installments during the severance period.

        Following any termination of employment other than one resulting from non-extension of the term, each of Messrs. Newby and Harrison will be subject to a post-termination non-competition covenant through the severance period. Following any termination of employment, each of Messrs. Newby and Harrison will be subject to a one-year post-termination non-solicitation covenant.

        In the case of Messrs. Newby and Harrison, if the named executive officer's employment is terminated due to non-extension of the term by us or by the named executive officer, we may choose to subject him to a non-competition covenant for up to one year post-termination. If we exercise this "noncompete option", then the named executive officer will be entitled to a severance payment in an amount equal to the sum of his annual base salary and annual bonus payable in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period.

        Any severance payment payable to a named executive officer pursuant to his employment agreement will be subject to his execution and non-revocation of a release of claims in favor of us.

152

---

        As described above, the Pre-IPO Equity Awards provide for certain acceleration in the event of certain terminations of employment, including certain terminations in connection with a change in control of Summit Investments.

2012 Long-Term Incentive Plan

        Prior to the consummation of this offering, our general partner intends to adopt a 2012 Long-Term Incentive Plan, or LTIP, pursuant to which our, our subsidiaries' and our general partner's eligible officers (including the named executive officers), employees, consultants and directors will be eligible to receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to our performance. The description of the LTIP set forth below is a summary of the anticipated material features of the LTIP. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the LTIP. In addition, our general partner is still in the process of implementing the LTIP and, accordingly, this summary is subject to change prior to the effectiveness of the registration statement of which this prospectus is a part.

        The LTIP will provide for the grant, from time to time at the discretion of the board of directors or compensation committee of our general partner, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of                        common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited will be available for delivery pursuant to other awards. We expect that the LTIP will be administered by our general partner's board of directors, though such administration function may be delegated to a committee (including the compensation committee) that may be appointed by the board to administer the LTIP. The LTIP will be designed to promote our interests, as well as the interests of our unitholders, by rewarding the officers, employees, consultants and directors of us, our subsidiaries and our general partner for delivering desired performance results, as well as by strengthening our and our general partner's ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Restricted Units and Phantom Units

        A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

        Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

        The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

153

---

Unit Options and Unit Appreciation Rights

        The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

        Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

        Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

        The LTIP may also permit the grant of "other unit-based awards," which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of an other unit-based award may be based on a participant's continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units; Cost

        Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Amendment or Termination of Long-Term Incentive Plan

        The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

154

---

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The following table sets forth certain information regarding the beneficial ownership of units following the closing of this offering and the related transactions by:

•

each person who is known to us to beneficially own 5% or more of such units to be outstanding;



•

our general partner;



•

each of the directors and named executive officers of our general partner; and



•

all of the directors and executive officers of our general partner as a group.

        All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

        The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of                        , 2012, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

155

---

        The percentage of units beneficially owned is based on a total of                        common units and                        subordinated units outstanding immediately following this offering.

156

---

157

---

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

        Immediately following the closing of this offering, Summit Investments will own                        common units and                         subordinated units, representing a combined        % limited partner interest in us (or                        common units and                        subordinated units, representing a combined         % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, Summit Investments will own and control our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to our General Partner and its Affiliates

        The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Summit Midstream Partners, LP These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Formation Stage

Operational Stage

158

---

Liquidation Stage

Agreements with Affiliates

        We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

Promissory Notes

        In conjunction with the purchase of the Grand River system, Summit Investments executed promissory notes, on an unsecured basis, with our sponsors. The notes totaled $200 million and had an 8% interest rate and a maturity date of October 27, 2013. The outstanding balance under the notes was paid in full on July 2, 2012.

EquiPower Electricity Management Services Agreement

        In December 2011, we entered into a consulting arrangement with EquiPower Resources Corp., or EquiPower, an affiliate of Energy Capital Partners, whereby EquiPower assists us with managing our electricity price risk. During the year ended December 31, 2011, we paid EquiPower $11,000 for such

159

---

services. Curtis A. Morgan, a member of the board of directors of our general partner, is the President and Chief Executive Officer of EquiPower.

Procedures for Review, Approval and Ratification of Related-Person Transactions

        The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

        The code of business conduct and ethics will provide that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

        The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

160

---

CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

        Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Summit Investments), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have duties to manage our general partner in a manner they subjectively believe is in the best interests of its owners. At the same time, the directors and executive officers of our general partner have a duty to manage us in a manner they subjectively believe is in our best interests.

        The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to the limited partners and the partnership. As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods for resolving conflicts of interest. Our partnership agreement also specifically defines the duties our general partner owes to us and our unitholders with respect to actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

        Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the Conflicts Committee. There is no requirement that our general partner seek the approval of the Conflicts Committee for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the Conflicts Committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.

        Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•

approved by the Conflicts Committee;



•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;



•

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or



•

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        If the resolution or course of action taken with respect to the conflict of interest satisfies any of the standards set forth in the first, third or fourth bullet points above, then such resolution or course of action will be deemed to be approved by all of our unitholders and, in the case of all four bullet points above, will not constitute a breach of our partnership agreement or of any duties our general partner may owe us or our unitholders.

        Our general partner may, but is not required to, seek approval from the Conflicts Committee of a resolution of a conflict of interest with our general partner or affiliates. Any matters approved by the Conflicts Committee will be presumed to have been approved in good faith. If our general partner does

161

---

not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and, in each case, in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he or she is acting in our best interests or meets the specified standard, for example, a transaction on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties. Please read "Management—Committees of the Board of Directors—Conflicts Committee" for information about the Conflicts Committee.

        Conflicts of interest could arise in the situations described below, among others.

Affiliates of our general partner may compete with us. Neither our partnership agreement nor any other agreement requires Summit Investments to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow.

        Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including Energy Capital Partners and GE Energy Financial Services, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, Energy Capital Partners and GE Energy Financial Services, through their investment funds and managed accounts, make investments and purchase entities in various areas of the energy sector, including the midstream natural gas industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, Energy Capital Partners and GE Energy Financial Services. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Energy Capital Partners and GE Energy Financial Services may compete with us for investment opportunities and may own an interest in entities that compete with us.

Our general partner is allowed to take into account the interests of parties other than us, such as Energy Capital Partners, in resolving conflicts.

        Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in the best interests of us or our unitholders, other than the implied contractual duty of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and

162

---

factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner's limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties and limits our general partner's liabilities and the rights of our unitholders with respect to actions that might otherwise constitute breaches of fiduciary duty under applicable Delaware law.

        In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duty. For example, our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;



•

provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, which means the subjective belief that the decision is in our best interests;



•

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) "fair and reasonable" to us, as determined by our general partner in good faith, provided that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and



•

provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its executive officers or directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

        Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

163

---

•

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;



•

the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;



•

the negotiation, execution and performance of any contracts, conveyances or other instruments;



•

the distribution of our cash;



•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;



•

the maintenance of insurance for our benefit and the benefit of our partners;



•

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;



•

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;



•

the indemnification of any person against liabilities and contingencies to the extent permitted by law;



•

the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and



•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

        Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in "good faith," our general partner must have a subjective belief that the determination is in our best interests. Please read "The Partnership Agreement—Voting Rights" for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

        The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•

the amount and timing of asset purchases and sales;



•

cash expenditures and the amount of estimated reserve replacement expenditures;



•

borrowings;



•

the issuance of additional units; and



•

the creation, reduction or increase of reserves in any quarter.

        Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

164

---

        In addition, our general partner may use an amount, initially equal to $             million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

        In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or



•

hastening the expiration of the subordination period.

        For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

        We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read "Certain Relationships and Related Party Transactions."

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

        Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm's-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.

        Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.

        Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

165

---

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner's limited call right.

        Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us free of any liability or obligation to us or our unitholders. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

        Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

        The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner's incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our public common unitholders in certain situations.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial minimum quarterly distribution and target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise

166

---

this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distribution of Available Cash—General Partner Interest and Incentive Distribution Rights."

Duties of Our General Partner

        The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify or eliminate, except for the contractual covenant of good faith and fair dealing, the fiduciary duties owed by the general partner to limited partners and the partnership.

        Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing the duties of the general partner to us and our unitholders and the methods for resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our general partner in a manner it believes is in the best interests of its owners. Without these provisions, our general partner's ability to make decisions involving conflicts of interest would be restricted. The replacement of fiduciary standards enable our general partner to take into consideration the interests of all parties involved. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions may be detrimental to our unitholders, however, because they restrict the rights and remedies that would otherwise be available to unitholders for actions that might otherwise constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

•

the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary;



•

the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware law on our general partner; and



•

certain rights and remedies of limited partners contained in the Delaware Act.

167

---

168

---

169

---

        By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

        Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read "The Partnership Agreement—Indemnification."

170

---

DESCRIPTION OF OUR COMMON UNITS

The Units

        The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Transfer Agent and Registrar

Duties

                                 will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by our unitholders:

•

surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;



•

special charges for services requested by a holder of a common unit; and



•

other similar fees or charges.

        There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

        The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

        By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;



•

represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and



•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

171

---

        Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

        We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

        Common units are securities and are transferable according to the laws governing the transfer of securities.

        Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

172

---

THE PARTNERSHIP AGREEMENT

        The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

        We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•

with regard to distributions of available cash, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions";



•

with regard to the duties of our general partner, please read "Conflicts of Interest and Duties";



•

with regard to the transfer of common units, please read "Description of Our Common Units—Transfer of Common Units"; and



•

with regard to allocations of taxable income and taxable loss, please read "Material Federal Income Tax Consequences."

Organization and Duration

        We were organized in Delaware in May 2012 and have a perpetual existence.

Purpose

        Our purpose under our partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

        Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than the business of gathering, compressing and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or our unitholders. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

        Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

Capital Contributions

        Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

        For a discussion of our general partner's right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read "—Issuance of Additional Securities."

173

---

Voting Rights

        The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a "unit majority" require:

•

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and



•

after the subordination period, the approval of a majority of the outstanding common units.

        By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

        In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of us or our unitholders.

174

---

Limited Liability

        Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

•

to remove or replace our general partner;



•

to approve some amendments to our partnership agreement; or



•

to take other action under our partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

        Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except

175

---

that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

        Our subsidiaries conduct business primarily in three states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

        Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

        Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.

        It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

        In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

        Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner

176

---

interest in us. Our general partner's 2.0% interest in us will be reduced if we issue additional units in the future (other than in those circumstances described above) and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership securities.

Amendment of Our Partnership Agreement

General

        Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, including any duty to act in the best interests of our partnership or our unitholders. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

        No amendment may be made that would:

•

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or



•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

        The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon the closing of this offering, affiliates of our general partner will own approximately        % of the outstanding common and subordinated units.

No Unitholder Approval

        Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;



•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;



•

a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited

177

---

partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•

a change in our fiscal year or taxable year and related changes;



•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;



•

an amendment that our general partner determines to be necessary or appropriate in connection with the authorization of issuance of additional partnership securities or rights to acquire partnership securities;



•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;



•

an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;



•

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;



•

mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or



•

any other amendments substantially similar to any of the matters described above.

        In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;



•

are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;



•

are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the units are or will be listed for trading;



•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or



•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

178

---

Opinion of Counsel and Limited Partner Approval

        Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under "—No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

        In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Sale or Other Disposition of Assets

        A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our unitholders.

        In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries' assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries' assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries' assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20.0% of our outstanding partnership securities immediately prior to the transaction.

        If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership

179

---

agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

        We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following the approval and admission of a successor general partner;



•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;



•

the entry of a decree of judicial dissolution of our partnership; or



•

there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

        Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•

the action would not result in the loss of limited liability of any limited partner; and



•

neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

        Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of Our General Partner

        Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to                        , 2022 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                        , 2022 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement

180

---

permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" and "—Transfer of Incentive Distribution Rights."

        Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."

        Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, and a majority of the outstanding subordinated units, voting as a single class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, affiliates of our general partner will own        % of the outstanding common and subordinated units.

        Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

•

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and



•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

        In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

        If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

181

---

        In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

        Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

•

an affiliate of our general partner (other than an individual); or



•

another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity, our general partner may not transfer all or any of its general partner interest to another person prior to                         , 2022 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

        Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

        At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

        Our general partner or its affiliates or a subsequent holder may transfer any or all of its incentive distribution rights without unitholder approval.

Change of Management Provisions

        Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read "—Meetings; Voting."

Limited Call Right

        If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be

182

---

selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

•

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and



•

the average of the daily closing prices of the partnership securities of such class for the 20 consecutive trading days preceding the date three days before the date the notice is mailed.

        As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Federal Income Tax Consequences—Disposition of Common Units."

Meetings; Voting

        Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

        Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

        Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

183

---

        Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

        By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

        If our general partner, with the advice of counsel, determines we are subject to U.S. federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the nationality, citizenship or other related status of our member (and their owners, to the extent relevant); and



•

permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by our general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Taxpaying Assignees; Redemption

        In the event any rates that we charge our customers become regulated by the Federal Energy Regulatory Commission, to avoid any adverse effect on the maximum applicable rates chargeable to customers by us, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the U.S. federal income tax status of our member (and their owners, to the extent relevant); and



•

permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

184

---

Indemnification

        Under our partnership agreement, we will indemnify the following persons, in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•

our general partner;



•

any departing general partner;



•

any person who is or was an affiliate of our general partner or any departing general partner;



•

any person who is or was a member, manager, partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;



•

any person who is or was serving at the request of the general partner or any departing general partner as an officer, director, member, manager, partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries; and



•

any person designated by our general partner.

        Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

        Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

        Our general partner is required to keep or cause to be kept appropriate books and records of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.

        We will furnish or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants, including a balance sheet and statements of operations, and our equity and cash flows. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

        We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to

185

---

assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

        Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:

•

a current list of the name and last known business, residence or mailing address of each partner;



•

a copy of our federal, state and local income tax returns;



•

true and full information as to the amount of cash, and a description and statement of the net agreed value of any other capital contribution by each partner and that each partner has agreed to contribute in the future, and the date on which each became a partner;



•

copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;



•

information regarding the status of our business and financial condition; and



•

any other information regarding our affairs as is just and reasonable.

        Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

        Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years and for so long thereafter as is required for the holder to sell its partnership securities following any withdrawal or removal of Summit Midstream GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read "Units Eligible for Future Sale."

186

---

UNITS ELIGIBLE FOR FUTURE SALE

        After the sale of the common units offered by this prospectus, Summit Investments will hold an aggregate of                        common units and                        subordinated units (or                        common units and                        subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

        The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1.0% of the total number of the securities outstanding; or



•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

        Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule's public information requirements, volume limitations, manner of sale provisions and notice requirements.

        Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."

        Under our partnership agreement, our general partner and its affiliates, excluding any individual who is an affiliate of our general partner, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

        Summit Investments, our general partner, each of our general partner's directors and officers and other owners have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Please read "Underwriting" for a description of these lock-up provisions.

187

---

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

        This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the "Treasury Regulations") and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Summit Midstream Partners, LP and our operating subsidiaries.

        The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose "functional currency" is not the U.S. dollar, persons holding their units as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

        No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

        All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

        For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales"); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees"); and

188

---

(iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Uniformity of Units").

Partnership Status

        A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner's adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than        % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

        No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•

We will be classified as a partnership for federal income tax purposes; and



•

Each of our operating subsidiaries will be disregarded as an entity separate from us for federal income tax purposes.

        In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

•

Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and



•

For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

        We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

        If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed

189

---

corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

        If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

        The discussion below is based on Latham & Watkins LLP's opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

        Unitholders of Summit Midstream Partners, LP will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Summit Midstream Partners, LP for federal income tax purposes.

        A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

        Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding common units in Summit Midstream Partners, LP. The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Summit Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

        Subject to the discussion below under "—Entity-Level Collections," we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

190

---

Treatment of Distributions

        Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units." Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

        A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," each as defined in the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder's tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

        We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending                                    , 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

        The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

191

---

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

        A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner's "net value" as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Limitations on Deductibility of Losses

        The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

        In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

        In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's investments in

192

---

other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

        A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

        The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;



•

our interest expense attributed to portfolio income; and



•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

        The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

        If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

        In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

193

---

        Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together referred to in this discussion as the "Contributed Property." The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, "reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

        An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity," will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•

his relative contributions to us;



•

the interests of all the partners in profits and losses;



•

the interest of all the partners in cash flow; and



•

the rights of all the partners to distributions of capital upon liquidation.

        Latham & Watkins LLP is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

        A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;



•

any cash distributions received by the unitholder as to those units would be fully taxable; and



•

all of these distributions would appear to be ordinary income.

194

---

        Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

        Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

        Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. These rates are scheduled to sunset after December 31, 2012, and, further, are subject to change by new legislation at any time.

        The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010 is scheduled to impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

        We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read "—Disposition of Common Units—Constructive Termination." The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets ("common basis") and (ii) his Section 743(b) adjustment to that basis.

195

---

        We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Units."

        We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units." A unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." Latham & Watkins LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

        A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

196

---

        The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

        We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

Initial Tax Basis, Depreciation and Amortization

        The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

        To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read "—Uniformity of Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

        If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

        The costs we incur in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication

197

---

expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties.

        The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

        Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

        Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

        Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

        The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred.

198

---

Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

        Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;



•

an offsetting notional principal contract; or



•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

        Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

        In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

        Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under

199

---

future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

        A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

        We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

        Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be

200

---

inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under "—Tax Consequences of Unit Ownership—Section 754 Election," Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

        Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

        Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

        In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

201

---

        A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

        We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

        The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

        Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

        The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders

202

---

having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

        A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

        Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;



•

whether the beneficial owner is:



•

a person that is not a U.S. person;



•

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or



•

a tax-exempt entity;



•

the amount and description of units held, acquired or transferred for the beneficial owner; and



•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

        Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties.

        An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

        For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, "substantial authority"; or



•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

        If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take

203

---

other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

        A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

        In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions.

        If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read "—Information Returns and Audit Procedures."

        Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties";



•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and



•

in the case of a listed transaction, an extended statute of limitations.

        We do not expect to engage in any "reportable transactions."

Recent Legislative Developments

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read "—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted.

204

---

However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

State, Local, Foreign and Other Tax Considerations

        In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property and do business in Texas and Colorado. Colorado imposes a personal income tax on individuals, and both Texas and Colorado impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

        It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

205

---

INVESTMENT IN SUMMIT MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

        An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, "Similar Laws." For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements, collectively, "Employee Benefit Plans." Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;



•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;



•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read "Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors"; and



•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

        The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

        Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving "plan assets" with parties that, with respect to the Employee Benefit Plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

        In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

        The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed "plan assets." Under these rules, an entity's assets would not be considered to be "plan assets" if, among other things:

•

(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

206

---

•

(b) the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or



•

(c) there is no significant investment by "benefit plan investors," which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

        Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

        In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

207

---

UNDERWRITING

        Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

        The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

•

the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;



•

the representations and warranties made by us to the underwriters are true;



•

there is no material change in our business or the financial markets; and



•

we deliver customary closing documents to the underwriters.

Commissions and Expenses

        The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

        We will pay a structuring fee equal to        % of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. for the evaluation, analysis and structuring of our partnership.

        The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $            per common unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

208

---

        We estimate that the expenses of this offering incurred by us will be $             million (excluding underwriting discounts and commissions and a structuring fee).

Option to Purchase Additional Common Units

        We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of                                    additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than                                    common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

        We, our general partner and its affiliates, including Summit Investments, and the directors and executive officers of our general partner have agreed that, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

        The 180-day restricted period described in the preceding paragraph will be extended if:

•

during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or



•

prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of the material event unless such extension is waived in writing by Barclays Capital Inc.

        Barclays Capital Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release the common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder's reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

209

---

Offering Price Determination

        Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated among the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

•

the history and prospects for the industry in which we compete;



•

our financial information;



•

the ability of our management and our business potential and earning prospects;



•

the prevailing securities markets at the time of this offering; and



•

the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

        We and certain of our affiliates, including Summit Investments, have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

        The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.



•

A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.



•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.



•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

210

---

        These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

        Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

        A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

        Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

        We intend to apply to list our common units on the New York Stock Exchange under the symbol "SMLP." The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

Discretionary Sales

        The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

        If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

        The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. The underwriters and their affiliates have

211

---

in the past, and may in the future, perform investment banking, commercial banking, advisory and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.

        In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

        Affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are lenders under our amended and restated revolving credit facility and, in that respect, will receive a portion of the net proceeds from this offering.

FINRA

        Because the Financial Industry Regulatory Authority, Inc., or FINRA, is expected to view the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

European Economic Area

        In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a "relevant member state"), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state, an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;



•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant dealer or dealers nominated by the issuer for any such offer; or



•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

        For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing

212

---

measure in each relevant member state. The expression "2010 PD Amending Directive" means Directive 2010/73/EU.

        We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

United Kingdom

        We may constitute a "collective investment scheme" as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a "recognized collective investment scheme" for the purposes of FSMA, or CIS, and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

          (i)  if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended, or the CIS Promotion Order, or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

         (ii)  otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or Financial Promotion Order, or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

        (iii)  in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as "relevant persons"). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

        An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

Switzerland

        This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

        We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or the CISA. Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private

213

---

placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Germany

        This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

        The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Netherlands

        Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

214

---

VALIDITY OF THE COMMON UNITS

        The validity of the common units offered hereby will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

        The consolidated financial statements of Summit Midstream Partners, LLC and subsidiaries as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor) included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph related to Summit Midstream Partners, LLC's acquisition of (1) the Grand River system from Encana Corporation on October 27, 2011 and (2) DFW Midstream Services LLC from Energy Future Holdings Corp., effective September 3, 2009). Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        The balance sheet of Summit Midstream Partners, LP included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC's web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

        As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website is located at                                    and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

        We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited

215

---

interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

        Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "will," "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

216

---

INDEX TO FINANCIAL STATEMENTS

F-1

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated
financial statements.

F-2

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated
financial statements.

F-3

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated
financial statements.

F-4

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE MONTHS ENDED (UNAUDITED)

Dollars in Thousands

   

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-5

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

        Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009. The Company is the predecessor for accounting purposes of Summit Midstream Partners, LP ("SMLP") who submitted a registration statement for its initial public offering of common units on a confidential basis. The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B membership interests in Summit Midstream (the "SMP Net Profits Interests") through their ownership in Summit Midstream Management, LLC.

        On October 4, 2011, the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10-25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development. The transaction closed on October 27, 2011, with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

        Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

        Basis of Presentation and Principles of Consolidation—The unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The unaudited condensed consolidated financial statements for the three months ended March 31, 2012 also include the operations of Grand River Gathering. The acquisition of Grand River Gathering closed on October 27, 2011.

F-6

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the results of operations for the three months ended March 31, 2012 and 2011. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). The unaudited condensed consolidated financial statements should be read in conjunction with the audited annual financial statements and related notes elsewhere in this prospectus. The results of operations for an interim period are not necessarily indicative of results expected for a full year. Subsequent events have been evaluated through July 17, 2012, the date these financial statements were available to be issued.

        The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

        Supplemental Unaudited Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, SMLP intends to distribute approximately $         million in cash to the Sponsors. Supplemental unaudited basic and diluted pro forma earnings per common unit for Summit Midstream Partners, LP for the three months ended March 31, 2012 assumed            general partner units,            subordinated units and            common units were outstanding in the period. The            common units consists of            common units issued to the Sponsors plus an additional            units, which is the number of common units that we would have been required to issue to fund the $             million distribution of net proceeds to the Sponsors. The number of common units that Summit Midstream Partners, LP would have been required to issue to fund the $             million distribution was calculated as $             million minus the Summit Midstream Partners, LLC net earnings of $             million for the year ended December 31, 2011 divided by an issue price per unit of $            , which is the initial public offering price of $            per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no securities convertible or exchangeable into common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

        The supplemental unaudited pro forma balance sheet as of March 31, 2012 gives pro forma effect to the assumed distribution discussed in the preceding paragraph, as though it had been declared and was payable as of that date.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Use of Estimates—The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

F-7

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Accounts Receivable—Accounts receivable relate to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At March 31, 2012 and December 31, 2011, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for services during any period presented.

        Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether future asset retirement obligations exist as of March 31, 2012 and December 31, 2011, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and dehydration facilities, as having an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company did not provide any asset retirement obligations as of March 31, 2012 and December 31, 2011 because it does not have sufficient information to reasonably estimate such obligations, and the Company has no current intention of discontinuing use of any significant assets.

        Revenue Recognition—The Company earns revenue from natural gas gathering services provided to natural gas producers and records such revenue as gathering services and other fees. The Company also earns revenue from the sale of physical natural gas retained from its customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. The Company records this revenue as natural gas and condensate sales. The Company records costs incurred which are reimbursed by its customers, on a gross basis in the consolidated statements of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

        The Company's natural gas gathering agreements provide a monthly or annual minimum volume commitment, or MVC, from certain of its customers. Under these monthly or annual MVCs, the Company's customers agree to ship a minimum volume of natural gas on the Company's gathering systems or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. If a customer's actual throughput volumes are less than its MVC for an applicable period, such customer must make a shortfall payment to the Company at the end of that contract month or year, as applicable. Under certain natural gas gathering agreements, customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC, ranging from twelve months to ten years.

        Billings to customers for obligations under their minimum volume commitments are recorded as deferred revenue. The Company recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. The Company

F-8

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

classifies deferred revenue as short-term for arrangements where the expiration of a customer's right to utilized shortfall payments is twelve months or less. As of March 31, 2012, the Company's customers have $3.2 million of shortfall payments, of which $1.8 million is included in accounts receivable as of March 31, 2012, attributed to arrangements that provide for the ability to offset gathering fees in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.

        Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 10 for a discussion of commitments and contingencies.

        Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

        Comprehensive Income—Comprehensive income is the same as net income for all periods presented.

        Earnings per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

        Unit Based Compensation—Certain of our current and former employees received Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC (collectively, the "Net Profits Interests"). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests are accounted for as compensatory awards. The Net Profits Interests vest ratably over four to five years, and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Summit LLC Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the Net Profits Interests as of the respective grant dates. The Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the Net Profits Interests: (a) assumptions underlying the enterprise value used in connection with the option pricing method, including the discount rate applied to estimated future cash flows, forecasted gathering volumes, revenues and costs, equity performance relative to peer group members, equity market risk premium, enterprise-specific risk premium, and terminal growth rates; (b) holding period restrictions; (c) discounts for lack of marketability; and (d) expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

F-9

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its condensed consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its condensed consolidated financial statements.

3. ACQUISITION OF GRAND RIVER GATHERING

        The Company completed the acquisition of Grand River Gathering from Encana for $590 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 270 miles of pipeline and 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos and Niobrara Shale development.

        The Grand River Transaction closed on October 27, 2011, with an effective date of October 1, 2011. The assets are owned by Grand River Gathering. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million.

        The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised of gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the Grand River Gathering gathering system. The Company has not completed the final purchase price allocation to the assets acquired and liabilities assumed as of March 31, 2012, because the Company is waiting to receive certain information in order to complete its determination of the values of acquired assets under construction, the related impacts on the valuation of the customer contract intangible assets and the final settlement of the purchase price.

F-10

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. ACQUISITION OF GRAND RIVER GATHERING (Continued)

        Fair values of the assets acquired and liabilities assumed as of October 27, 2011, are as follows:

        The Company determined that the purchase price was equal to the fair value of the net assets acquired; thus, no goodwill was recorded.

        Unaudited Pro Forma Financial Information—The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the transactions had occurred on those dates, or what the Company's financial position or results from operations will be for any future periods. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that we recorded for the two month period from November 1, 2011 through December 31, 2011. The Company incurred transaction costs of $3,160, which are not included in net income presented immediately below, as the pro forma information assumes the transaction occurred January 1, 2010.

4. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY

        On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from Texas Competitive Electric Holdings Company LLC (the "DFW Transaction"). The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable

F-11

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

intangible assets and a noncurrent liability, which are subject to amortization as of March 31, 2012 and December 31, 2011, are composed of the following:

 

        Amortization expense of $319 and $375 for the three month periods ended March 31, 2012 and 2011 related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

        Amortization expense of $3,350 for the three month period ended March 31, 2012 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in the depreciation and amortization expense in the statements of operations. The intangible asset contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

        Amortization expense of $314 and $185 for the three month periods ended March 31, 2012 and 2011 related to rights-of-way associated with city easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        The unfavorable contract included within noncurrent liability relates to an unfavorable gas gathering contract that was deemed to be below market upon the acquisition of DFW Midstream. Amortization related to the unfavorable gas gathering contract was $453 and $305 for the three month periods ended March 31, 2012 and 2011, and was recorded within revenue. The unfavorable contract is

F-12

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

        The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from March 31, 2012 is as follows:

        There are no indefinite-lived intangible assets recorded as of March 31, 2012 or December 31, 2011.

5. PROPERTY, PLANT, AND EQUIPMENT—NET

        Net property, plant, and equipment is composed of the following:

        Depreciation expense related to property, plant, and equipment was $4,626 and $1,420 for the three months ended March 31, 2012 and 2011. The Company capitalized interest totaling $1,321 and zero during the three months ended March 31, 2012 and 2011.

6. REVOLVING CREDIT FACILITY

        On May 26, 2011, Holdings closed a senior secured revolving credit facility with total commitments of $285 million. The revolving credit facility, which matures in May 2016, contains a $150 million accordion provision that enables Holdings to increase the total size of the facility any time prior to maturity. The revolving credit facility allows for revolving loans, letters of credit and swingline loans. The revolving credit facility is secured by the membership interests of Holdings and DFW Midstream and substantially all of Holdings' and DFW Midstream's assets and is guaranteed by Holdings'

F-13

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

6. REVOLVING CREDIT FACILITY (Continued)

subsidiaries. Borrowings under the revolving credit facility bear interest at London Interbank Offered Rate (LIBOR) plus an applicable margin or a base rate, as defined in the credit agreement. Under the terms of the revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at March 31, 2012. As of March 31, 2012, availability under the revolving credit facility totaled $138 million. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of March 31, 2012 was 2.75%.

        The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of March 31, 2012, Holdings was in compliance with all applicable covenants.

        The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners. As of March 31, 2012, there was $147 million outstanding under the facility.

        On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed $163 million under the facility (bringing total borrowings under the facility to $310 million). Additionally, Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. The amended and restated revolving credit facility matures in May 2016.

7. PROMISSORY NOTES PAYABLE TO SPONSORS

        In conjunction with the purchase of Grand River Gathering, the Company executed promissory notes, on an unsecured basis, with its Sponsors. The notes totaled $200 million, mature on October 27, 2013, and have an 8% interest rate. The Company has the option to elect to pay the interest in kind and the Company made this election for all interest due as of March 31, 2012. The amount of interest paid in kind and accrued to the balance of the notes for the three months ended March 31, 2012, is

F-14

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

7. PROMISSORY NOTES PAYABLE TO SPONSORS (Continued)

$4,047, resulting in $206,940 as the amount outstanding on the notes as of March 31, 2012. During the three months ended March 31, 2012, the Company capitalized $565 of the $4,047 interest expense related to costs incurred on capital projects under construction. As of March 31, 2012, the aggregate carrying value of these notes approximated the fair value. On May 8, 2012 the Company borrowed $163 million under the amended and restated revolving credit facility and used a portion of the same borrowings to prepay $160 million of the promissory notes payable to sponsors. On July 2, 2012, the Company borrowed $50 million under the amended and restated revolving credit facility and used a portion of the same borrowings to prepay the remaining $49.2 million of the promissory notes payable to Sponsors.

8. INCOME TAXES

        No provision for federal income taxes or state income taxes are included in our results of operations as such income is taxable directly to our owners. However, we are subject to income taxes in the state of Texas. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $139 and $73, for the three months ended March 31, 2012 and 2011.

9. MEMBERSHIP INTERESTS

        As of March 31, 2012, Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

        In accordance with the Summit LLC Agreement, capital accounts are maintained for the Company's members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's condensed consolidated financial statements.

        The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests described above.

F-15

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

9. MEMBERSHIP INTERESTS (Continued)

        During the three months ended March 31, 2012, the Company, with assistance from a third-party valuation expert, determined the fair value of the SMP Net Profits Interests as of the respective grant date for the grant made on January 25, 2012. The SMP Net Profits Interests granted on January 25, 2012, were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of Summt Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class.

        A significant input of the option pricing method is the enterprise value of the Company, as well as the length of holding period and volatility of our equity securities. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the Company. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the Company's peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the Company's estimated future cash flows.

        Additional significant inputs used in the option pricing method for the SMP Net Profits Interests granted on January 25, 2012 are as follows:

        Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests as of March 31, 2012 is presented below.

        The Company recognizes compensation expense ratably over the five year vesting period. Non-cash compensation expense (recorded in general and administrative expense) related to the three months ended March 31, 2012 and 2011 was $307 and $111. The Company recorded non-cash compensation expense of $463 during the three months ended March 31, 2011 related to 2010 and 2009. As of March 31, 2012, the unrecognized non-cash compensation expense for the remaining vesting period is

F-16

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

9. MEMBERSHIP INTERESTS (Continued)

$4,554. Incremental non-cash compensation expense will be recorded over the remaining expected weighted average vesting period of 3.9 years.

        DFW Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. All grants vest ratably over 4 years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement an LLC Agreement).

        Information regarding the amount and grant-date fair value of the vested and nonvested DFW Net Profits Interests as of March 31, 2012 is presented below.

        The Company recognizes compensation expense ratably over the four year vesting period. Non-cash compensation expense (recorded in general and administrative expense) related to the three months ended March 31, 2012 and 2011 was $153 and $58. The Company recorded non-cash compensation expense of $582 in the three months ended March 31, 2011 related to 2010 and 2009. As of March 31, 2012, the unrecognized non-cash compensation expense for the remaining vesting period is $1,167. Incremental non-cash compensation expense will be recorded over the remaining expected weighted average vesting period of 1.9 years.

10. COMMITMENTS AND CONTINGENCIES

        Contractual Commitments—The Company leases office space in Dallas, Texas, Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas, and has determined that its leases are classified as operating leases.

        Total rent expense related to operating leases was $137 and $55 for the three month periods ended March 31, 2012 and 2011, and was recorded within general and administrative.

        Legal Proceedings—The Company is involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on the Company's financial condition, results of operations, or liquidity.

F-17

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

11. RELATED-PARTY TRANSACTIONS

        Promissory Notes Payable to Sponsors—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 7)

        Electricity Management Services Agreement—The Company entered into a consulting arrangement with Equipower Resources Corp. ("Equipower"), an affiliate of Energy Capital Partners, whereby Equipower assists the Company with managing its electricity price risk. During the three month periods ended March 31, 2012 and 2011, the Company paid Equipower $44 and zero for such services.

        Diligence Expenses—In the past, the Sponsors reimbursed the Company for transactional due diligence expenses related to proposed transactions that were not completed. As of March 31, 2012 and December 31, 2011, the Company had a receivable from the Sponsors of $0 and $1,309, respectively, for similar expenses. During the three months ended March 31, 2012 the company was reimbursed $319 while $990 was not paid.

        Transition Services Agreement—The Company executed a transition services agreement with TCEH effective September 3, 2009. The services provided to the Company by TCEH included the temporary use of TCEH office space; ongoing utilization of accounting and financial reporting services support; general support regarding any administration of Consolidated Omnibus Budget Reconciliation Act (COBRA) health benefits; general information technology support to manage data files, addresses, network connectivity, etc.; and use of computers, right-of-way services, and public relation services. The costs and rates charged to the Company by TCEH related to each service were negotiated and mutually agreed to by both parties. The termination date related to each service provided under the agreement varies with the option to extend certain services if deemed necessary and agreed to by both parties. The extension periods are in three-month intervals beginning January 1, 2010, and are limited to 18 months in total. As of March 31, 2012, the only services provided under the agreement that remain relate to the right-of-way services. The amounts charged to the Company through the transition services agreement for the three month periods ended March 31, 2012 and 2011, were $8 and $14.

12. CONCENTRATIONS OF RISK

        Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and accounts receivable. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.

        Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale of natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the Company's customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

        For the three month periods ended March 31, 2012 and 2011, the Company had three customers (each comprising over 10% of total revenue) that accounted for approximately 65% and 58% of total

F-18

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. CONCENTRATIONS OF RISK (Continued)

gas revenue. The total accounts receivable from these customers accounted for approximately 60% and 51% of accounts receivable as of March 31, 2012 and December 31, 2011.

        The following tables summarize concentrations of revenue in excess of 10% of total revenue for the three month periods ended March 31, 2012 and 2011, and accounts receivable in excess of 10% of accounts receivable as of March 31, 2012 and December 31, 2011:

******

F-19

---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC
Dallas, Texas

        We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LLC and subsidiaries (the "Company") as of December 31, 2011 and 2010 (Successor), and the related consolidated statements of operations, membership interests, and cash flows for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor) and for the period from January 1, 2009 through September 3, 2009 (Predecessor). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, (Successor) and for the years ended December 31, 2011 and 2010 (Successor), for the period from September 3, 2009 (Inception) through December 31, 2009 (Successor), and for the period from January 1, 2009 through September 3, 2009 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 4 to the consolidated financial statements, the Company acquired Grand River Gathering Company, LLC on October 27, 2011. Also, as discussed in Note 3 to the consolidated financial statements, the Company acquired a controlling interest in DFW Midstream Services LLC on September 3, 2009.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-20

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-21

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-22

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERSHIP INTERESTS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

 

   

The accompanying notes are an integral part of these consolidated financial statements.

F-23

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

F-24

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

Dollars in Thousands

   

The accompanying notes are an integral part of these consolidated financial statements.

F-25

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS

        Organization—Summit Midstream Partners, LLC (the "Company" or "Summit Midstream"), a Delaware limited liability company, was formed and began operations on September 3, 2009 (inception). The Company's business strategy is to own and operate a portfolio of midstream energy infrastructure assets that are strategically located in the core areas of unconventional resource basins in North America. Through August 17, 2011, the Company was wholly-owned by Energy Capital Partners II, LP and its parallel and co-investment funds (collectively, "Energy Capital Partners" or "Sponsor"). On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services" or "Sponsor", collectively with Energy Capital Partners, "Sponsors"). Subsequent to the sale of this noncontrolling interest to GE Energy Financial Services, Energy Capital Partners continues to control the activities of Summit Midstream through its representation on the Company's board of managers. Certain members of the Summit Midstream management hold ownership interests in the form of Class B Units in Summit Midstream through their ownership in Summit Midstream Management, LLC.

        Concurrent with the Company's formation on September 3, 2009, the Company acquired a controlling interest in DFW Midstream Services LLC ("DFW Midstream"), and accordingly, the DFW Midstream Limited Liability Company Agreement was amended and restated to effect among other things (i) the continuation of Texas Competitive Electric Holdings Company LLC ("TCEH") as a Class A Member, (ii) the admission of Summit Midstream as a Class A Member, (iii) the admission of DFW Midstream Management LLC as the Class B Member, and (iv) the continuation of DFW Midstream as a Delaware limited liability company. The acquisition of a controlling interest in DFW Midstream by Summit Midstream was accounted for under the acquisition method of accounting. Summit Midstream's consolidated financial statements reflect DFW Midstream's operations for all periods presented.

        On June 2, 2010, Summit Midstream purchased all of TCEH's remaining membership interests in DFW Midstream. The transaction was completed on June 18, 2010. The purchase of the remaining noncontrolling interest in DFW Midstream was accounted for as an equity transaction (see Note 10).

        On October 4, 2011 the Company entered into a purchase and sale agreement with Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation ("Encana"), to acquire certain natural gas gathering pipeline, dehydration and compression assets in western Colorado for $590 million. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10-25 years. In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development. The transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly owned subsidiary of the Company ("Grand River Gathering"). The transaction was funded through an equity contribution and an aggregate of $200 million in promissory notes from the Sponsors.

F-26

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        Business Operations—Summit Midstream's two operating subsidiaries are DFW Midstream and Grand River Gathering. Both are midstream energy companies focused on the development, construction and operation of natural gas gathering systems. DFW Midstream's gathering system is located in the core of the Barnett Shale located in the Fort Worth basin in Texas. Grand River Gathering's gathering system is located in the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado.

        Basis of Presentation—The consolidated financial statements include the assets, liabilities, and results of operations of the Company and its wholly-owned subsidiaries Summit Midstream Holdings, LLC ("Holdings"), Grand River Gathering and DFW Midstream, and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The consolidated financial statements for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, reflect the application of purchase accounting related to the acquisition of a controlling interest in DFW Midstream by Summit Midstream on September 3, 2009. The consolidated financial statements also include the operations of Grand River Gathering upon the closing of the transaction on October 27, 2011.

        The consolidated financial statements provided for the period from January 1, 2009 through September 3, 2009, include only the operations of DFW Midstream which is the predecessor of Summit Midstream. These financial statements represent the results of operations, changes in membership interest and cash flows of DFW Midstream and have been carved out of the accounting records maintained by Energy Future Holdings Corp. and its subsidiaries ("Energy Future Holdings"). Historically, Energy Future Holdings did not allocate general and administrative ("G&A") expenses to DFW Midstream for any centralized finance and administrative costs. Accordingly, the financial statements for the period from January 1, 2009 through September 3, 2009 (inception) include an estimate of G&A for the period of $588 based on the level of significance of DFW Midstream to Energy Future Holdings, the number of employees directly involved in DFW Midstream and considering the capital intensive nature of the activities of DFW Midstream during this period. The estimate of G&A expenses was predominantly related to rent, insurance and other employee related expenses. Because of the nature of these carved-out financial statements, the intercompany advances from Energy Future Holdings were reported within an intercompany advances account, and immediately prior to the acquisition, were converted to membership interest.

        All intercompany transactions have been eliminated upon consolidation. Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

        The Company's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems and related plant and equipment.

        The Company is the predecessor for accounting purposes of Summit Midstream Partners, LP ("SMLP") who submitted a registration statement for its initial public offering of common units on a confidential basis.

F-27

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

1. ORGANIZATION AND BUSINESS OPERATIONS (Continued)

        Supplemental Unaudited Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, SMLP intends to distribute approximately $             million in cash to the Sponsors. Supplemental unaudited basic and diluted pro forma earnings per common unit for Summit Midstream Partners, LP for the year ended December 31, 2011 assumed                         general partner units,                         subordinated units and                        common units were outstanding in the period. The                        common units consists of             common units issued to the Sponsors plus an additional                        units, which is the number of common units that we would have been required to issue to fund the $             million distribution of net proceeds to the Sponsors. The number of common units that SMLP would have been required to issue to fund the $             million distribution was calculated as $             million minus the Company's net earnings of $37.4 million for the year ended December 31, 2011 divided by an issue price per unit of $            , which is the initial public offering price of $            per common unit less the estimated underwriting discounts, structuring fee and offering expenses. There were no potential common units outstanding to be considered in the pro forma diluted earnings per unit calculation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Use of Estimates—The consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

        Cash and Cash Equivalents—Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

        Accounts Receivable—Accounts receivable relate to gathering and other services provided to independent natural gas producer customers. Accounts receivable included in the balance sheets are net of an allowance for doubtful accounts. At December 31, 2011 and 2010, the Company recorded no allowance for doubtful accounts. The Company did not experience non-payment for services during any period presented.

        Intangible Assets and Liabilities—Intangible assets and unfavorable contracts consisting of favorable and unfavorable gas gathering contracts are amortized on a units-of-production basis over the life of the contract, which is the period over which the contracts are expected to contribute directly or indirectly to the Company's future cash flows. The favorable and unfavorable contracts relate to gas gathering contracts that were deemed to be above or below market at the acquisition of DFW Midstream. The contract lengths range from 10 years to 20 years.

F-28

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Intangible assets consisting of contract values related to the Grand River Gathering gas gathering agreements are amortized over the period of economic benefit based upon the expected revenues over the life of the contract, which range from 10 years to 25 years.

        Right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way are amortized over the shorter of the contractual term of the rights-of-way, ranging from 20 years to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        Property, Plant, and Equipment—Property, plant, and equipment are recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.

        Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

        Impairment of Long-Lived Assets—Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows. The Company did not recognize any impairment of long-lived assets during any period presented.

        Other Noncurrent Assets—Other noncurrent assets primarily consist of external costs incurred in connection with the closing of the Company's revolving credit facility and costs incurred related to the Company's contemplated initial public offering. Deferred loan costs are capitalized and amortized over the life of the related agreement. Amortization of deferred loan costs is included in interest expense in the statement of operations.

F-29

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Asset Retirement Obligations—Accounting standards related to asset retirement obligations require the Company to evaluate whether any future asset retirement obligations exist as of December 31, 2011 and 2010, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and dehydration facilities, have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company did not provide any asset retirement obligations as of December 31, 2011 and December 31, 2010 because it does not have sufficient information to reasonably estimate such obligations, and the Company has no current intention of discontinuing use of any significant assets.

        Revenue Recognition—The Company earns revenue from natural gas gathering services provided to natural gas producers and records such revenue as gathering services and other fees. The Company also earns revenue from the sale of physical natural gas retained from its customers to offset power expenses associated with electric-driven compression on the DFW Midstream system and condensate retained from gathering services. The Company records this revenue as natural gas and condensate sales. The Company records costs incurred which are reimbursed by its customers, on a gross basis in the consolidated statements of operations. Revenue is recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable and (iv) collectability is reasonably assured.

        Commitments and Contingencies—The consolidated financial results of the Company may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 8 for a discussion of commitments and contingencies.

        Environmental Matters—The operations of the Company and the Predecessor are subject to various federal, state and local laws and regulations relating to the protection of the environment. Although the Company believes that it is in compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation, and there can be no assurances that significant costs and liabilities will not be incurred by the Company. Management is not aware of any contingent liabilities that currently exist with respect to environmental matters.

        Income Taxes—Provision for income taxes is attributable to the Company's state tax obligations under the gross margin tax enacted by the State of Texas. Since the Company is structured as a partnership for federal income tax purposes, the Company is not subject to federal income taxes. As a result, the Company's members are individually responsible for paying federal income taxes on their

F-30

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

share of the Company's taxable income. See Note 9 for additional information regarding the Company's income taxes.

        Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.

        Comprehensive Income (Loss)—Comprehensive income (loss) is the same as net income (loss) for all periods presented.

        Earnings Per Unit—Earnings per unit has not been presented because the Company's members hold interests and not units.

        Recent Accounting Pronouncements—Accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its consolidated financial statements. There are currently no recent pronouncements that have been issued that the Company believes will materially affect its consolidated financial statements.

        Unit Based Compensation—Certain of our current and former employees received Class B membership interests, classified as net profits interests, in DFW Midstream Management LLC or Summit Midstream Management, LLC (collectively, the "Net Profits Interests"). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests are accounted for as compensatory awards. The Net Profits Interests vest ratably over four to five years, and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the Summit LLC Agreement). With the assistance of a third-party valuation firm, we determined the fair value of the Net Profits Interests as of the respective grant dates. The Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of either the DFW Midstream Management LLC or Summit Midstream Management, LLC, and considers the rights and preferences of each class of equity in order to allocate a fair value to each class. See Note 10.

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM

        On September 3, 2009, the Company acquired a controlling interest in DFW Midstream from TCEH (the "DFW Transaction"). At the date of the DFW Transaction, the Company received a capital contribution from Energy Capital Partners of $107,000 and contributed $85,082 to DFW Midstream in exchange for a 75% membership interest. Concurrently, DFW Midstream purchased certain natural gas gathering assets under construction located in the Barnett Shale from a division of Chesapeake Energy Corporation for $44,896, and a distribution of $40,186 was made by DFW Midstream to TCEH.

F-31

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

        The Company accounted for the DFW Transaction under the acquisition method of accounting, whereby the total purchase price of the DFW Transaction was allocated to DFW Midstream's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of September 3, 2009. The intangible assets acquired were right-of-way easements (weighted average life of 28.6 years) and favorable gas gathering agreements (weighted average life of 18.7 years). The intangible liabilities acquired were unfavorable gas gathering agreements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete DFW Midstream's gathering system. The purchase price was estimated by imputing the value of 100% of the membership interests in DFW Midstream based upon $85,082 in cash contributed by Summit Midstream in exchange for an economic interest in DFW Midstream equal to 70.5% of future distributions and the obligation to contribute 75% of the project completion budget. The purchase price was equal to the fair value of the net assets of DFW Midstream; thus, no goodwill was recorded.

        Fair values of the assets acquired and liabilities assumed as of September 3, 2009 are as follows:

        In connection with the DFW Transaction, TCEH contributed assets consisting of property, plant and equipment related assets primarily under construction, gas gathering contracts and rights-of-way. The fair value of property, plant and equipment was determined utilizing the cost approach because of the early stage of construction or certain of the related assets having been recently purchased at the time of the DFW Transaction. The fair value of the gas gathering contracts was determined utilizing a discounted cash flow approach based upon the forecasted volumes under the applicable contract and the difference between the contractual and market rates for similar services in the area. The rights-of-way were valued based upon similar acreage and utilizing an assemblage factor for the contiguous easements acquired.

F-32

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

3. PURCHASE OF CONTROLLING INTEREST IN DFW MIDSTREAM (Continued)

        The noncontrolling interest in DFW Midstream held by TCEH at September 3, 2009, was estimated based on TCEH's economic interest in DFW Midstream equal to 29.5% of future distributions and the obligation to contribute 25% of the capital expenditures in the project completion budget, and was adjusted to reflect the lack of control and lack of marketability that market participants would be expected to consider when estimating the fair value of the noncontrolling interest in DFW Midstream.

        In connection with the DFW Transaction, the Company incurred $3,921 in transaction costs, which were expensed as incurred and are reported within transaction costs. Such costs include $1,075 paid to Energy Capital Partners Management II, LP, a related party; $1,103 paid to Energy Capital Partners Management LP, a related party; and $1,743 paid to third parties (of which $1,603 was paid by Energy Capital Partners on behalf of the Company) for strategic, advisory, management, legal, and consulting services. Transaction costs paid by Energy Capital Partners are presented as a noncash capital contribution.

4. ACQUISITION OF GRAND RIVER GATHERING

        The Company completed the acquisition of Grand River Gathering from Encana for $590 million, effective October 1, 2011 (the "Grand River Transaction"). The Grand River Gathering natural gas midstream assets are located in the Piceance Basin. The acquired assets include approximately 260 miles of pipeline and 90,000 horsepower of compression facilities. These assets gather production from the Mamm Creek, Orchard, and South Parachute fields in the area around Rifle, Colorado. The assets gather natural gas under long-term contracts ranging from 10 years to 25 years (weighted average life of 12.8 years). In addition to the purchase, the Company has a contractual relationship with Encana related to the development of midstream infrastructure to support Encana's emerging Mancos Shale and Niobrara development.

        The Grand River Transaction closed on October 27, 2011 with an effective date of October 1, 2011. The assets are owned by Grand River Gathering, LLC, a wholly-owned subsidiary of the Company. The Grand River Transaction was funded through an equity contribution of $410 million and promissory notes from the Sponsors totaling $200 million. For the period ended December 31, 2011, the Company recorded $12,824 of revenue and $2,111 of net income related to Grand River Gathering.

        The Company accounted for the Grand River Transaction under the acquisition method of accounting, whereby the total purchase price of the Grand River Transaction was allocated to Grand River Gathering's identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of October 27, 2011. The intangible assets that were acquired are comprised gas gathering agreement contract values and right-of-way easements. The fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete Grand River Gathering's gathering system. The Company has not completed the final purchase price allocation to the assets acquired and liabilities assumed as of December 31,

F-33

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

2011, because the Company is waiting to receive certain information in order to complete its determination of the values of acquired assets under construction, the related impacts on the valuation of the customer contract intangible assets and the final settlement of the purchase price.

        Fair values of the assets acquired and liabilities assumed as of October 27, 2011 are as follows:

        The Company determined that the purchase price was equal to the fair value of the net assets acquired; thus, no goodwill was recorded.

        Unaudited Pro Forma Financial Information—The following unaudited pro forma financial information assumes that the Grand River Gathering acquisition occurred on January 1, 2010 and the DFW Midstream acquisition (see Note 3) occurred on January 1, 2009. Transaction costs of $3,160 related to the acquisition of Grand River Gathering have been adjusted and recorded in 2010 for the proforma information below. The unaudited pro forma information is not necessarily indicative of what the Company's financial position or results of operation would have been if the transactions had occurred on those dates, or what the Company's financial position or results from operations will be for any future periods.

        Pro forma adjustments for the year ended December 31, 2011 consist of $64,119 of revenue and $11,610 of net income for January through October of 2011 and $76,943 of revenue and $12,665 for the year ended December 31, 2010 related to Grand River Gathering assuming the acquisition date was January 1, 2010. These pro forma adjustments were derived by annualizing the actual operating results for Grand River Gathering that we recorded for the two month period from November 1, 2011 through

F-34

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

4. ACQUISITION OF GRAND RIVER GATHERING (Continued)

December 31, 2011. The transaction costs of $3,160 have been removed from the year ended December 31, 2011 and reflected in the year ended December 31, 2010. Pro forma adjustments for the year ended December 31, 2009 represent $39 of revenue and $654 of depreciation related to DFW Midstream assuming the DFW Transaction was effective January 1, 2009.

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY

        The Company accounted for the DFW Transaction and the Grand River Transaction under the acquisition method of accounting and identified separately identifiable intangible assets and a noncurrent liability. Identifiable intangible assets and a noncurrent liability, which are subject to amortization as of December 31, 2011 and 2010, are composed of the following:

 

        Amortization expense of $1,718, $764, $40, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to the favorable gas gathering contract intangible assets was recorded within revenue. The favorable contract relates to a gas gathering contract that was deemed to be above market upon the acquisition of DFW Midstream. The favorable contract intangible assets are amortized on a units-of-production basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Company's future cash flows.

        Amortization expense of $2,412 for the year ended December 31, 2011 related to the intangible contract values of the gas gathering agreements at Grand River Gathering was recorded and is included in the depreciation and amortization expense in the statement of operations. The intangible asset

F-35

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

5. IDENTIFIABLE INTANGIBLE ASSETS AND NONCURRENT LIABILITY (Continued)

contract values are amortized over the period of economic benefit based upon the expected revenues over the life of the contract.

        Amortization expense of $908, $519, $114, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, related to rights-of-way associated with city easements and easements granted within existing rights-of-way was recorded within depreciation and amortization expense over the shorter of the contractual term of the rights-of-way, ranging from 20 to 30 years, or the estimated useful life of the gathering system, which is 30 years.

        The unfavorable contract included within noncurrent liability relates to an unfavorable gas gathering contract that was deemed to be below market upon the acquisition of DFW Midstream. Amortization related to the unfavorable gas gathering contract was $1,410, $549, $60, and $0 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within revenue. The unfavorable contract is amortized on a units-of-production basis over its estimated useful life, which is the period over which the liability is expected to contribute directly or indirectly to the Company's future cash flows.

        The estimated aggregate amortization of intangible assets and a noncurrent liability for each of the five succeeding fiscal years from December 31, 2011 is as follows:

        There are no indefinite-lived intangible assets recorded as of December 31, 2011 or 2010.

F-36

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

6. PROPERTY, PLANT, AND EQUIPMENT—NET

        Net property, plant, and equipment as of December 31, 2011 and 2010, is composed of the following:

        Depreciation expense related to property, plant, and equipment was $8,595, $3,355, $230, and $882 for the years ended December 31, 2011 and 2010, the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively. The Company capitalized interest totaling $3,362 during the year ended December 31, 2011 and zero in any other period.

7. REVOLVING CREDIT FACILITY

        On May 26, 2011, Holdings closed a senior secured revolving credit facility with total commitments of $285 million. The revolving credit facility, which matures in May 2016, contains a $150 million accordion provision that enables Holdings to increase the total size of the facility any time prior to maturity. The revolving credit facility allows for revolving loans, letters of credit and swingline loans. The revolving credit facility is secured by the membership interests of Holdings and DFW Midstream and substantially all of Holdings' and DFW Midstream's assets and is guaranteed by Holdings' subsidiaries. Borrowings under the revolving credit facility bear interest at London Interbank Offered Rate ("LIBOR") plus an applicable margin or a base rate, as defined in the credit agreement. Under the terms of the revolving credit facility, the applicable margin under LIBOR borrowings was 2.50% at December 31, 2011. As of December 31, 2011, availability under the revolving credit facility totaled $138 million. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. The weighted-average interest rate as of December 31, 2011 was 2.88%.

        The revolving credit facility requires Holdings to maintain a ratio of consolidated trailing 12-month EBITDA to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to six months following certain acquisitions (as defined in the credit agreement). As of December 31, 2011, Holdings was in compliance with all applicable covenants.

F-37

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

7. REVOLVING CREDIT FACILITY (Continued)

        The revolving credit facility contains restrictive covenants that prohibit the declaration or payment of distributions by Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Holdings can make. An event of default may result in the acceleration of Holdings' repayment of outstanding borrowings under the revolving credit facility, the termination of the revolving credit facility and foreclosure on collateral. Upon closing of the facility, the Company made a distribution of $132.9 million to Energy Capital Partners. As of December 31, 2011, there was $147 million outstanding under the facility.

        On May 7, 2012, Holdings closed on an amendment and restatement of its revolving credit facility, which expanded its borrowing capacity to $550 million from $285 million. Upon closing of the senior secured amended and restated revolving credit facility, the Company contributed its assets and membership interests in Grand River Gathering to Holdings and Holdings borrowed $163 million under the facility. As of May 11, 2012, we had $307 million of indebtedness under our revolving credit facility. Holdings utilized $160 million of the borrowings at closing to partially repay the promissory notes payable to Sponsors. The amended and restated credit facility is secured by the membership interests of Holdings, DFW Midstream and Grand River Gathering and substantially all of Holdings', DFW Midstream's and Grand River Gathering's assets and is guaranteed by Holdings' subsidiaries. The amended and restated revolving credit facility contains affirmative and negative covenants customary for credit facilities of this size and nature, that, among other things, limit or restrict the ability to incur additional debt, make investments, engage in certain mergers, consolidations, acquisitions or sales of assets, enter into swap agreements and power purchase agreements and enter into leases that would cumulatively obligate payments in excess of $30 million over any 12-month period. The interest costs, other fees and financial covenants of the amended and restated revolving credit facility are consistent with the May 2011 revolving credit facility. The amended and restated revolving credit facility matures in May 2016.

8. PROMISSORY NOTES PAYABLE TO SPONSORS

        In conjunction with the purchase of Grand River Gathering, the Company executed promissory notes, on an unsecured basis, with its Sponsors. The notes totaled $200 million, mature on October 27, 2013 and have an 8% interest rate. The Company has the option to elect to pay the interest in kind and the Company made this election for all interest due as of December 31, 2011. The amount of interest paid in kind and accrued to the balance of the notes as December 31, 2011 is $2,893, resulting in $202,893 as the amount outstanding on the note as of December 31, 2011. During 2011, the Company capitalized $868 of the $2,893 interest expense related to costs incurred on capital projects under construction. As of December 31, 2011, the aggregate carrying value of these notes approximated the fair value. On May 7, 2012, the Company amended and restated its revolving credit facility. On May 8, 2012, the Company borrowed $163 million under the amended and restated revolving credit facility and used the same borrowings to prepay $160 million of the promissory notes payable to

F-38

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

8. PROMISSORY NOTES PAYABLE TO SPONSORS (Continued)

Sponsors. As of May 11, 2012, the balance under the promissory notes payable to Sponsors was $48,695.

9. INCOME TAXES

        In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax (i.e., the Texas Margin Tax), including nontaxable entities such as limited liability companies, limited partnerships, and limited liability partnerships. The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas Margin Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The income tax provision recorded in operations associated with the Texas Margin Tax was $695, $124, $7, and $8, for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, and the period from January 1, 2009 through September 3, 2009, respectively.

10. MEMBERSHIP INTERESTS

        As described in Note 1, Summit Midstream is controlled by Energy Capital Partners through Energy Capital Partners' ownership of Class A membership interests in the Company. On August 17, 2011, Energy Capital Partners sold an 11.25% membership interest in the Company to GE Energy Financial Services, therefore as of December 31, 2011 Energy Capital Partners holds an 88.75% interest and GE Energy Financial Services holds an 11.25% interest in Summit Midstream. As of December 31, 2010 and 2009, Energy Capital Partners held all of the Company's membership interests. Such membership interests gives the Sponsors the right to participate in distributions and to exercise the other rights or privileges available to each entity under the Company's Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement").

        In accordance with the Summit LLC Agreement, capital accounts are maintained for the Company's members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

        The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests described above.

F-39

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        Contemporaneously with the formation of Summit Midstream and the execution of the Summit LLC Agreement at September 3, 2009, Class B membership interests (the "SMP Net Profits Interests") up to 7.5% of Summit Midstream's total membership interests were authorized and 2.85% were granted to certain members of Summit Midstream Management, LLC. SMP Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested SMP Net Profits Interests. The SMP Net Profits Interests are accounted for as compensatory awards. Additional SMP Net Profits Interests were granted on April 1, 2010, April 1, 2011, and October 18, 2011. All grants vest ratably over 5 years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and Summit LLC Agreement). As of December 31, 2011, 5.855% of SMP Net Profits Interests had been granted, and no SMP Net Profits Interests had been forfeited.

        During the year ended December 31, 2011, the Company, with assistance from a third-party valuation expert, determined the fair value of the SMP Net Profits Interests as of the respective grant dates for the grants made prior to that date. Therefore, the 2011 awards were valued contemporaneously within the year issued, and the 2009 and 2010 awards were valued retrospectively. The SMP Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of Summit Midstream and considers the rights and preferences of each class of equity in order to allocate a fair value to each class.

        A significant input of the option pricing method is the enterprise value of the Company. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the Company. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the Company's peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the Company's estimated future cash flows.

        Additional significant inputs used in the option pricing method for the SMP Net Profits Interests granted in each of the years designated below are as follows:

F-40

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests as of December 31, 2009, 2010, and 2011 is presented below.

        The Company recognizes compensation expense ratably over the five year vesting period. The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $1,269 which included $463 related to years prior to 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 3.2 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $3,971.

        In connection with the Company's formation and acquisition of DFW Midstream on September 3, 2009, Energy Capital Partners contributed $107,000 to the Company in order to initially capitalize the Company and fund the Company's investment in DFW Midstream. Energy Capital Partners contributed an additional $27,871 of capital to Summit Midstream through December 31, 2009. Energy Capital Partners made cash contributions of $194,134 to the Company for the year ended December 31, 2010, which were primarily used to fund ongoing capital expenditures of DFW Midstream and purchase the

F-41

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

remaining noncontrolling interest in DFW Midstream from TCEH on June 18, 2010, as discussed below.

        In connection with the closing of the Company's revolving credit facility in May 2011, the Company distributed $132,943 to Energy Capital Partners.

        Noncontrolling Interest in DFW Midstream—During the three years ended December 31, 2011, the Company has had several changes in membership interests related to the ownership of its consolidated subsidiary DFW Midstream as discussed further below. At December 31, 2011 and 2010, 100% of the Class A membership interests of DFW Midstream were held by Summit Midstream or its direct subsidiary, Holdings. Summit Midstream, through its subsidiary Holdings, as the sole Class A Member, holds units that represent membership interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement (collectively the "LLC Agreement"). The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive.

        In accordance with the LLC Agreement, capital accounts are maintained for the members. The capital account provisions of the LLC Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in the Company's consolidated financial statements.

        The LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that Class A Members will receive. Prior to Summit's purchase of TCEH's remaining interest in DFW Midstream on June 18, 2010 (as discussed immediately below), Summit held a 75% interest and TCEH held a 25% Class A membership interest; however, distributions and allocations of income and loss are based on a sharing percentage as defined in the LLC Agreement resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit and TCEH, respectively. Capital contributions required under the LLC Agreement are in proportion to the owners' respective percentage ownership interests.

        In 2010, Summit Midstream and TCEH entered into a Membership Interest Purchase Agreement whereby Summit Midstream purchased all of TCEH's membership interests in DFW Midstream for cash consideration of $90,722. Amounts reported as noncontrolling interest relate to TCEH's ownership interests in DFW Midstream prior to June 18, 2010. The change in Summit Midstream's ownership interest in DFW Midstream resulted in a decrease in membership interest of $25,126 for the year ended December 31, 2010, as the cash consideration paid exceeded the carrying value of the noncontrolling interest at June 18, 2010.

        Distributions and allocations of income and loss for the periods presented prior to June 18, 2010, are based upon a sharing percentage as defined in the Amended and Restated LLC Agreement of DFW Midstream resulting in an allocation or distribution on a basis of 70.5% and 29.5% for Summit

F-42

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

Midstream and TCEH, respectively. Net income (loss) of $78 and $(400) was allocated to TCEH, as the noncontrolling interest holder, based upon its ownership interests and profits and losses allocation for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively.

        TCEH funded capital contributions in the amount of $10,720 and $15,417 for the year ended December 31, 2010, and for the period from September 3, 2009 (inception) through December 31, 2009, respectively. Additionally, in connection with the Company's acquisition of DFW Midstream on September 3, 2009, DFW Midstream distributed $40,186 to TCEH as a return of capital.

        Contemporaneously with the execution of the LLC Agreement on September 3, 2009, up to 5% of DFW Midstream's total membership interests were authorized for issuance as Class B membership interests (the "DFW Net Profits Interests) and an aggregate of 4.50% of DFW Net Profits Interests were granted to certain members of DFW Midstream Management LLC. DFW Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. Additional DFW Net Profits Interests were granted on April 1, 2010 and July 28, 2010. All grants vest ratably over 4 years and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and LLC Agreement). As of December 31, 2011, 4.80% of DFW Net Profits Interests had been granted and 0.40% DFW Net Profits Interests had been forfeited.

        During the year ended December 31, 2011, the Company, with assistance from a third-party valuation expert, determined the fair value of the DFW Net Profits Interests as of the respective grant dates for the grants made prior to that date. Therefore, the 2009 and 2010 awards were valued retrospectively. The DFW Net Profits Interests were valued utilizing an option pricing method, which models the Class A and Class B membership interests as call options on the underlying equity value of DFW Midstream and considers the rights and preferences of each class of equity in order to allocate a fair value to each class.

        A significant input of the option pricing method is the enterprise value of DFW Midstream. We estimated the enterprise value utilizing a combination of the income and market approaches. The income approach utilized the discounted cash flow method, whereby we applied a discount rate to estimated future cash flows of the DFW Midstream. Key inputs include forecasted gathering volumes, revenues and costs; unlevered equity betas of the DFW Midstream peer group; equity market risk premium; company-specific risk premium; and terminal growth rate. Under the market approach, trading multiples of the securities of publicly-traded peer companies were applied to the DFW Midstream's estimated future cash flows.

F-43

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

        Additional significant inputs used in the option pricing method for the DFW Net Profits Interests granted in each of the years designated below are as follows:

        Information regarding the amount and grant-date fair value of the vested and nonvested DFW Net Profits Interests as of December 31, 2009, 2010, and 2011 is presented below.

        The Company recognizes compensation expense ratably over the four year vesting period. The Company recorded non-cash compensation expense (recorded in general and administrative expense) in 2011 of $2,171 which included $582 related to years prior to 2011. During the year ended

F-44

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

10. MEMBERSHIP INTERESTS (Continued)

December 31, 2011, the Company modified the awards to remove a rate of return payout hurdle and as a result of the modification; the Company valued the Class B Units immediately prior to and following the modification to determine incremental compensation expense. The modification resulted in the immediate expense of $1,358 attributed to the previously vested Class B Units which is included in the $1,589 of compensation expense recorded during the year ended December 31, 2011. Incremental unit based compensation will be recorded over the remaining expected weighted average vesting period of 2.1 years. As of December 31, 2011, the unrecognized compensation expense for the remaining vesting period is $1,321.

        Predecessor Membership Interests—Prior to the DFW Transaction, TCEH funded the Company's construction activities and working capital needs through intercompany loans or advances that accrued interest at an average rate of 4.29% for the predecessor period. Immediately prior to the DFW Transaction, the advances were converted to a membership interest.

11. COMMITMENTS AND CONTINGENCIES

        Contractual Commitments—The Company leases office space for its headquarters in Dallas, Texas and for other offices in Atlanta, Georgia, Houston, Texas and Grand Prairie, Texas , and has determined that its leases are classified as operating leases. A schedule of future minimum lease payments for operating leases that had initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011 is as follows:

        Total rent expense related to operating leases was $489, $212, $28, and $0 for the years ended December 31, 2011 and 2010, and for the period from September 3, 2009 (inception) to December 31, 2009, the period from January 1, 2009 through September 3, 2009, respectively, and was recorded within general and administrative.

        Legal Proceedings—The Company is involved in various legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on the Company's financial condition, results of operations, or liquidity.

F-45

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

12. RELATED-PARTY TRANSACTIONS

        Transaction Costs—As discussed in Note 3, during 2009 the Company paid transaction costs of $1,075 and $1,103 to Energy Capital Partners Management II, LP and Energy Capital Partners Management, LP, respectively.

        Diligence Expenses—The Sponsors agreed to reimburse the Company for previous transactional due diligence expenses related to proposed transactions that were not completed. As of December 31, 2011, the Company had a receivable from the Sponsors of $1,309 related to this previous agreement.

        Transition Services Agreement—The Company executed a transition services agreement with TCEH effective September 3, 2009. The services provided to the Company by TCEH included the temporary use of TCEH office space; ongoing utilization of accounting and financial reporting services support; general support regarding any administration of Consolidated Omnibus Budget Reconciliation Act (COBRA) health benefits; general information technology support to manage data files, addresses, network connectivity, etc.; and use of computers, right-of-way services, and public relation services. The costs and rates charged to the Company by TCEH related to each service were negotiated and mutually agreed to by both parties. The termination date related to each service provided under the agreement varies with the option to extend certain services if deemed necessary and agreed to by both parties. The extension periods are in three-month intervals beginning January 1, 2010, and are limited to 18 months in total. As of December 31, 2011, the only services provided under the agreement that remain relate to the right-of-way services. The amounts charged to the Company through the transition services agreement for the years ended December 31, 2011 and 2010 and for the period from September 3, 2009 (inception) through December 31, 2009, were $39, $137 and $100, respectively.

        Promissory Notes—The Company has entered into promissory note agreements with its owners in conjunction with the acquisition of Grand River Gathering. (See Note 8)

        Electricity Management Services Agreement—The Company entered into a consulting arrangement with EquiPower Resources Corp. ("EquiPower"), an affiliate of Energy Capital Partners, whereby EquiPower assists the Company with managing its electricity price risk. During the years ended December 31, 2011 and 2010, the Company paid EquiPower $11 and zero for such services, respectively.

13. CONCENTRATIONS OF RISK

        Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and accounts receivable. The Company maintains its cash in bank deposit accounts that, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.

        Accounts receivable are primarily from natural gas producers shipping natural gas and from natural gas marketers' purchase and sale of natural gas. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the Company's

F-46

---

SUMMIT MIDSTREAM PARTNERS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2011 AND 2010 (SUCCESSOR) AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010 (SUCCESSOR), FOR THE PERIOD FROM SEPTEMBER 3, 2009 (INCEPTION) THROUGH DECEMBER 31, 2009 (SUCCESSOR), AND FOR THE PERIOD FROM JANUARY 1, 2009 THROUGH SEPTEMBER 3, 2009 (PREDECESSOR)

DOLLARS IN THOUSANDS UNLESS OTHERWISE NOTED

13. CONCENTRATIONS OF RISK (Continued)

customers may be similarly affected by changes in economic, industry or other conditions. The Company monitors the creditworthiness of all of its counterparties. The Company generally requires letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

        For the years ended December 31, 2011 and 2010, the Company had four customers (each comprising over 10% of total revenue) that accounted for approximately 73% and 88% of total gas revenue, respectively. The total accounts receivable from these customers accounted for approximately 66% and 95% of accounts receivable for the years ended December 31, 2011 and 2010, respectively.

        The following tables summarize concentrations of revenue and accounts receivable in excess of 10% of total revenue and accounts receivable as of and for the years ended December 31, 2011 and 2010, for the period from September 3, 2009 (inception) through December 31, 2009 and for the period from January 1, 2009 through September 3, 2009, respectively:

******

F-47

---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Summit Midstream Partners, LLC as general partner of Summit Midstream Partners, LP
Dallas, Texas

        We have audited the accompanying balance sheet of Summit Midstream Partners, LP (the "Partnership") as of May 10, 2012. The balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on the balance sheet based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Partnership as of May 10, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Dallas, Texas
May 11, 2012

F-48

---

SUMMIT MIDSTREAM PARTNERS, LP

BALANCE SHEET

MAY 10, 2012

F-49

---

SUMMIT MIDSTREAM PARTNERS, LP

NOTE TO BALANCE SHEET

1. Nature of Operations

        Summit Midstream Partners, LP (the "Partnership") is a Delaware limited partnership formed on May 1, 2012 to acquire certain assets and related contracts and agreements from the operating subsidiaries of Summit Midstream Partners, LLC. In order to simplify the Partnership's obligations under the laws of selected jurisdictions in which the Partnership will conduct business, the Partnership's activities will be conducted through a wholly owned limited liability company.

        Summit Midstream GP, LLC, as general partner, contributed $20 and Summit Midstream Partners, LLC, as the organizational limited partner, contributed $980 to the Partnership on May 10, 2012.

2. Summary of Significant Accounting Policies

Basis of Presentation

        This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America. Separate statements of operations, membership interests, and cash flows have not been presented because the entity has had no business transactions or activities to date.

Subsequent Events

        Subsequent events have been evaluated through May 11, 2012, the date these financial statements were available to be issued.

3. Commitments and Contingencies

        As of the date of these financial statements, Summit Midstream Partners, LP had no outstanding commitments and contingencies.

F-50

---

APPENDIX A
FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF
SUMMIT MIDSTREAM PARTNERS, LP

To be filed by amendment.

A-1

---

APPENDIX B
GLOSSARY OF TERMS

        condensate:    A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

        dry gas:    A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

        end users:    The ultimate users and consumers of transported energy products.

        Mcf:    One thousand cubic feet.

        MMBtu:    One million British Thermal Units.

        MMBtu/d:    One million British Thermal Units per day.

        MMcf:    One million cubic feet.

        MMcf/d:    One million cubic feet per day.

        NGLs:    Natural gas liquids. The combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

        NYMEX:    New York Mercantile Exchange.

        play:    A proven geological formation that contains commercial amounts of hydrocarbons.

        receipt point:    The point where production is received by or into a gathering system or transportation pipeline.

        residue gas:    The natural gas remaining after being processed or treated.

        tailgate:    Refers to the point at which processed natural gas and natural gas liquids leave a processing facility for end-use markets.

        Tcf:    One trillion cubic feet.

        throughput volume:    The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

        wellhead:    The equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.

B-1

---

Summit Midstream Partners, LP

Common Units
Representing Limited Partner Interests

---

Prospectus

                         , 2012

---

Barclays

BofA Merrill Lynch

Goldman, Sachs & Co.

Morgan Stanley

        Until                    , 2012 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

---

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        Set forth below are the expenses (other than underwriting discounts, commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

Item 14.    Indemnification of Directors and Officers.

Summit Midstream Partners, LP

        Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled "The Partnership Agreement—Indemnification" discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

        The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Summit Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Summit Midstream GP, LLC

        Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

        Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

II-1

---

•

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;



•

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and



•

any person designated by our general partner.

        Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15.    Recent Sales of Unregistered Securities.

        On May 10, 2012, in connection with the formation of Summit Midstream Partners LP, we issued (i) the 2.0% general partner interest in us to Summit Midstream GP, LLC for $20, and (ii) a 98% limited partner interest in us to Summit Midstream Partners, LLC for $980, in each case in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

Item 16.    Exhibits and Financial Schedules.

        The following documents are filed as exhibits to this registration statement:

II-2

---

Item 17.    Undertakings

        The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

        Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

        The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.



(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.



(3)

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than

II-3

---

prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(4)

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

          (i)  Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

         (ii)  If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use;

        (iii)  Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

        (iv)  The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

         (v)  Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

        The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Summit Midstream GP, LLC our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Summit Midstream GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

        The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-4

---

SIGNATURES

        Pursuant to the to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on [    •    ], 2012.

        Each person whose signature appears below appoints Steven J. Newby and Brock M. Degeyter, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

II-5

---

        Pursuant to the requirements of the Securities Act of 1933, as amended this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

II-6

---

EXHIBIT INDEX

        The following documents are filed as exhibits to this registration statement:

---