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•	Item 1. Business;

•	Item 1A. Risk Factors;

•	Item 2. Properties;

•	Item 6. Selected Financial Data;

•	Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations;

•	Item 7A. Quantitative and Qualitative Disclosures About Market Risk;

•	Item 8. Financial Statements and Supplementary Data;

•	Item 11. Executive Compensation;

•	Exhibit 12.1 Ratio of Earnings to Fixed Charges;

•	Exhibit 21.1 List of Subsidiaries; and

•	Exhibit 23.1 Consent of Deloitte & Touche LLP.

•	changes in general economic conditions;

•	fluctuations in crude oil, natural gas and natural gas liquids prices;

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•	the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within proximity of our assets;

•	failure or delays by our customers in achieving expected production in their natural gas and crude oil projects;

•	competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering and processing assets or systems;

•	actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements;

•	our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition;

•	the ability to attract and retain key management personnel;

•	commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;

•	changes in the availability and cost of capital, and the results of our financing efforts, including availability of funds in the credit and/or capital markets;

•	restrictions placed on us by the agreements governing our debt instruments;

•	the availability, terms and cost of downstream transportation and processing services;

•	operating hazards, natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;

•	weather conditions and seasonal trends;

•	timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

•	the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;

•	the effects of litigation; and

•	certain factors discussed elsewhere in this current report on Form 8-K.

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•	the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;

•	the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•	the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

•	the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah.

•	the Mountaineer Midstream system, which serves the Appalachian Basin;

•	the Bison Midstream system, which serves the Williston Basin;

•	the DFW Midstream system, which serves the Fort Worth Basin; and

•	the Grand River system, which serves the Piceance Basin.

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Mountaineer Midstream System. The Mountaineer Midstream system is located in the Appalachian Basin and currently serves Antero, which is targeting liquids-rich natural gas production from the Marcellus Shale formation in Harrison and Doddridge counties in West Virginia. The Mountaineer Midstream system serves as a critical inlet to the Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia. The Sherwood Processing Complex is owned and operated by MarkWest Energy Partners, L.P. (“MarkWest”). We are currently in the process of expanding throughput capacity on the Mountaineer Midstream system from 550 MMcf/d to 1,050 MMcf/d to support Antero's current and future anticipated drilling activities in this prolific region of the Marcellus Shale Play.

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Bison Midstream System. The Bison Midstream system is located in the Williston Basin and currently serves producers that are targeting the Bakken and Three Forks shale formations in Mountrail and Burke counties in northwestern North Dakota. These formations are primarily targeted for crude oil production and producer drilling decisions are based largely on the prevailing price of crude oil. The Bison Midstream system gathers and compresses associated natural gas that exists in the crude oil production stream. Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's ("Aux Sable") Palermo Conditioning Plant in Palermo, North Dakota. Once conditioned, the natural gas is delivered to Aux Sable pipelines serving its 2.1 Bcf/d natural gas processing plant in Channahon, Illinois. We believe that the pace of drilling activity and thus, natural gas volume throughput on the Bison Midstream system, will primarily depend on the price of crude oil, which provides diversity of commodity price exposure for us relative to our other natural gas midstream operations.

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DFW Midstream System. The DFW Midstream system is primarily located in southeastern Tarrant County, the largest natural gas producing county in Texas. 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. The DFW Midstream system currently has five primary interconnections with third-party, intrastate

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Grand River System. The Grand River system is located in the Piceance Basin in western Colorado and eastern Utah and currently serves producers targeting the liquids-rich Mesaverde formation as well as the emerging Mancos and Niobrara shale formations. Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) Enterprise Products Partners L.P.'s ("Enterprise") Meeker Natural Gas Processing Plant, a 1.7 Bcf/d processing facility located in Meeker, Colorado, (ii) Williams Partners L.P.'s Northwest Pipeline system, and (iii) Kinder Morgan Energy Partners L.P.'s TransColorado Pipeline system. Processed NGLs from the Grand River system are injected into Enterprise's Mid-America Pipeline system. The Grand River system also includes a new medium-pressure gathering system to handle future natural gas production from the emerging Mancos and Niobrara shale formations. We believe that the Grand River system is optimally located for expansion to gather production from these shale formations underlying the Mesaverde formation.

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Pursuing accretive acquisition opportunities from Summit Investments. We intend to pursue opportunities to expand our asset base by acquiring midstream assets owned and operated by and under development at Summit Investments. In addition to its significant ownership interest in us, Summit Investments owns and operates, and seeks to acquire and develop, crude oil, natural gas and water-related midstream assets in service and under construction in geographic areas in which we currently operate as well as in geographic areas outside of our current areas of operations. For example, in January 2014, Summit Investments acquired an interest in two entities (collectively, “Ohio Gathering”) that own, operate and are developing significant midstream infrastructure in southeastern Ohio consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate transportation, storage and stabilization facility in the core of the Utica shale. While Summit Investments has indicated that it intends to offer us the opportunity to acquire its interests in Ohio Gathering, it is not under any contractual

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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 primarily provided under long-term, fee-based contracts with original terms ranging from five years to 25 years. We believe that our focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows.

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Capitalizing on organic growth opportunities to maximize throughput on our existing systems. We intend to continue to leverage our management team's expertise in constructing, developing and optimizing our midstream infrastructure assets to grow our business through organic development projects. We believe that our broad and geographically diverse operating footprint provides us with a competitive advantage to pursue organic development projects that are designed to extend our geographic reach, diversify our customer base, expand our midstream service offerings, increase the number of our hydrocarbon receipt points and maximize volume throughput.

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Diversifying our asset base by expanding our midstream service offerings and exploring acquisition and development opportunities in various geographic areas. While our natural gas gathering operations in the Piceance Basin and the Barnett, Bakken, and Marcellus shale plays currently represent our core business, we intend to diversify into other midstream services such as crude oil gathering, through both greenfield development projects and acquisitions from affiliated and non-affiliated parties. We also intend to diversify our operations into other geographic regions.

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Partnering with producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We seek to promote commercial relationships with established and well-capitalized producers who are willing to serve as anchor customers and commit to long-term MVCs and AMIs. We will continue to pursue partnership opportunities with established producers to develop new infrastructure in unconventional resource basins that we believe will complement our existing midstream assets and/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 that is well-positioned for accelerated production but has limited existing midstream energy infrastructure to support such growth.

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Strategically located assets in core areas of prolific unconventional basins supported by partnerships with large producers. Our assets are strategically positioned within the core areas of four established unconventional resource plays. The geologic formations in the basins served by our assets have either relatively low drilling and completion costs, highly economic production profiles, or a combination of both which incentivize producers to develop more actively than in more marginal areas.

•	Fee-based revenues underpinned by long-term contracts with AMIs and MVCs. A substantial majority of our revenue for the year ended December 31, 2013 was generated under long-term, fee-based gas gathering and processing agreements. We believe that long-term, fee-based gas gathering and processing agreements enhance the stability of our cash flows by limiting our direct commodity price exposure.

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Capital structure and financial flexibility. At December 31, 2013, we had $586.0 million of total indebtedness and the unused portion of our $700.0 million amended and restated revolving credit facility totaled $414.0 million. Under the terms of the revolving credit facility, our total leverage ratio (total net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) was approximately 3.7 to 1.0 at December 31, 2013, which compares with a total leverage ratio upper limit of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions (as defined in the credit agreement).

•	Experienced management team with a proven record of asset acquisition, construction, development, operation and integration expertise. Our senior leadership team has an average of 19

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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 energy assets. We believe the relationship with our Sponsors is a competitive advantage as they bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will continue to benefit us as we seek to grow our business.

•	the Mountaineer Midstream system in northern West Virginia;

•	the Bison Midstream system in northwestern North Dakota;

•	the DFW Midstream system in north-central Texas; and

•	the Grand River system in western Colorado and eastern Utah.

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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

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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 and satisfied the requirements of its aggregate MVC in 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 contract terms of our MVCs.

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To the extent that certain of our customers' 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 in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.

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•	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;

•	adopt and maintain procedures, standards and training programs for control room operations; and

•	implement preventive and mitigating actions.

•	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.

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•	the volume of natural gas we gather, treat and process;

•	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, crude oil, natural gas and NGLs;

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

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

•	weather conditions and seasonal trends;

•	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, crude oil, natural gas and NGLs, 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.

•	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;

•	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.

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•	the availability and cost of capital;

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

•	demand for crude 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.

•	worldwide economic conditions;

•	weather conditions and seasonal trends;

•	the levels of domestic production and consumer demand;

•	the availability of imported liquefied natural gas ("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 crude oil, natural gas, LNG and other commodities.

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To the extent that a customer's throughput volumes are less than its minimum volume commitment 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 minimum volume commitment for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer's monthly or annual minimum volume commitment (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).

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To the extent that a customer's throughput volumes exceed its minimum volume commitment in the applicable period, it may be entitled to apply the excess throughput against its aggregate minimum volume commitment, thereby reducing the period for which its annual minimum volume commitment applies. For example, one of our DFW Midstream customers had a contracted minimum volume commitment term from October 2010 through September 2017. However, this customer regularly shipped volumes in excess of its minimum volume commitments and satisfied the requirements of its aggregate minimum volume commitment in less than three years. As a result of this mechanism, the weighted-average remaining period for which our minimum volume commitments apply is less than the weighted-average of the original stated terms of our minimum volume commitments.

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To the extent that certain of our customers' 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 in the event that there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement. In such a situation, we

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•	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 minimum volume commitments have been satisfied with previous throughput volume shipments.

•	the level of existing and new competition to provide gathering and/or processing services to our markets;

•	the macroeconomic factors affecting natural gas gathering and processing economics for our current and

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•	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.

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•	unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;

•	restrictions imposed by governmental authorities or court proceedings;

•	labor difficulties that result in a work stoppage or slowdown;

•	a disruption in the supply of resources necessary to operate our midstream facilities;

•	damage to our facilities resulting from natural gas or NGLs that do not comply with applicable specifications; and

•	inadequate transportation or market access to support production volumes, including lack of availability of pipeline capacity.

•	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;

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•	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.

•	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;

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•	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;

•	customer or key employee losses at the acquired businesses; and

•	production declines higher than anticipated and facilities being properly constructed.

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•	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;

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•	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.

•	incur or guarantee additional debt;

•	make cash 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 or otherwise engage in a change of control; and

•	transfer, sell or otherwise dispose of assets.

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•	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 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 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; and

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

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•	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;

•	adopt and maintain procedures, standards and training programs for control room operations; and

•	implement preventive and mitigating actions.

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Neither our partnership agreement nor any other agreement requires SMP Holdings or 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. SMP Holdings or Summit Investments may choose to shift the focus of their investment and growth to areas not served by our assets.

•	SMP Holdings and Summit Investments are not limited in their 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 SMP Holdings and Summit Investments and their owners, in resolving conflicts of interest.

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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.

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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 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.

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Our partnership agreement permits us to classify up to $50.0 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.

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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 other unitholders in certain situations.

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•	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 or changes in financial estimates by analysts;

•	future sales of our common units; and

•	other factors described in these Risk Factors.

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•	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.

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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;

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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:

(i)	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;

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

(iii)	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(iv)	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.

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•	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;

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

•	the market price of the common units may decline.

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

•	an investor's 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.

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(i)

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

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

(iii)	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; and

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

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•	Natural gas supply and demand dynamics;

•	Growth in production from U.S. shale plays;

•	Interest rate environment; and

•	Rising operating costs and inflation.

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•	throughput volume;

•	operation and maintenance expenses;

•	EBITDA and adjusted EBITDA; and

•	distributable cash flow.

•	successful drilling activity within our areas of mutual interest;

•	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 areas of mutual interest awaiting connections;

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

•	our ability to gather, treat and process natural gas that has been released from commitments with our competitors.

•	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 financial performance of our assets without regard to the impact of the timing of minimum volume commitments shortfall payments under our gas gathering agreements, the impact of unit-based compensation or the timing of gain or loss on asset sales.

•	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.

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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 revolving credit facility and future issuances of equity and debt securities. Prior to the IPO, we largely relied on internally generated cash flows and capital contributions from the Sponsors to satisfy our capital expenditure requirements;

•	Our historical results of operations may not be comparable to our future results of operations due in part to:

(i)

Our June 2013 acquisitions. The audited consolidated financial statements reflect the results of operations of: (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. Due to the common control aspect, the Bison Drop Down was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed. Common control began on February 16, 2013 concurrent with Summit Investments' acquisition of the assets that comprise the Bison Midstream system. For additional information, see Notes 1, 5, 6 and 13 to the audited consolidated financial statements;

(ii)

Grand River Gathering's March 2014 acquisition of Red Rock Gathering. The audited consolidated financial statements reflect the results of operations of Red Rock Gathering since October 23, 2012. Due to the common control aspect, the Red Rock Drop Down was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed. Common control began on October 23, 2012 concurrent with Summit Investments' acquisition of Red Rock Gathering. For additional information, see Notes 1 and 13 to the audited consolidated financial statements;

(iii)	Our IPO, which was completed on October 3, 2012. Incremental public entity costs 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 NYSE;

•	independent auditor fees;

•	legal fees;

•	investor relations expenses;

•	registrar and transfer agent fees;

•	director and officer liability insurance costs; and

•	director compensation.

(iv)	Our October 2011 acquisition of Grand River Gathering. The audited consolidated financial statements reflect the results of operations of Grand River Gathering since November 1, 2011. For additional information, see Notes 1 and 13 to the audited consolidated financial statements.

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

•	EBITDA, adjusted EBITDA, and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

•	EBITDA, adjusted EBITDA, and distributable cash flow 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, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and

•	our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measures of other companies.

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•	cash generated from operations;

•	borrowings under the revolving credit facility; and

•	additional issuances of debt and equity securities.

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•	Distributions declared in respect of the fourth quarter of 2012 (paid in the first quarter of 2013) and the first, second, and third quarters of 2013 (see Note 6 to the audited consolidated financial statements);

•	Borrowings of $381.0 million under our revolving credit facility, of which $200.0 million was used to partially fund the Bison Drop Down and $110.0 million was used to partially fund the Mountaineer Acquisition (see Notes 5, 6 and 13 to the audited consolidated financial statements);

•

Net proceeds of $294.2 million from our issuance of $300.0 million senior notes, all of which was used to pay down our revolving credit facility. In addition, we incurred loan costs in connection with the senior notes issued in June 2013 and in connection with the amendment and restatement of our revolving credit facility in November 2013 (see Notes 2 and 5 to the audited consolidated financial statements);

•	Issuance of $98.0 million of common units and $2.0 million of general partner interests to affiliates for cash to partially fund the Mountaineer Acquisition (see Notes 6 and 13 to the audited consolidated financial statements); and

•	Our repurchase of the remaining vested DFW Net Profits Interests (see Notes 8 and 11 to the audited consolidated financial statements).

•

Borrowings of $163.0 million under the revolving credit facility in May 2012, of which we used $160.0 million to prepay principal amounts outstanding under certain unsecured promissory notes payable to the Sponsors and borrowings of $50.0 million in July 2012, of which we used $49.2 million to repay the balance of the unsecured promissory notes payable to the Sponsors (see Notes 5 and 10 to the audited consolidated financial statements); and

•

Proceeds of $263.1 million from the issuance of our common units in connection with our IPO (including the proceeds from the exercise of the underwriters' option to purchase additional common units). We used $140.0 million of the IPO proceeds to pay down our revolving credit facility. We also paid $88.0 million to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it

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•	Proceeds of $200.0 million from the execution of promissory notes payable to the Sponsors to fund a portion of the purchase of the Grand River system (see Note 10 to the audited consolidated financial statements);

•	Contributions of $410.0 million from the Sponsors to acquire the Grand River system and $15.0 million to support capital needs related to the construction of the DFW Midstream system (see Note 13 to the audited consolidated financial statements); and

•	Distributions to Energy Capital Partners of $132.9 million out of the $147.0 million drawn on the revolving credit facility (see Note 5 to the audited consolidated financial statements).

•	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.

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•	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;

•	holding period restrictions;

•	discounts for lack of marketability; and

•	expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available.

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•	Summit Investments conveyed an interest in Summit Midstream Holdings, LLC ("Summit Holdings") to our general partner as a capital contribution;

•	our general partner conveyed its interest in Summit Holdings to SMLP in exchange for (i) a continuation of its 2% general partner interest in SMLP, represented by 996,320 general partner units, and (ii) SMLP incentive distribution rights, or IDRs;

•

Summit Investments conveyed its remaining interest in Summit Holdings to SMLP in exchange for (i) 10,029,850 common units (net of the impact of selling 1,875,000 common units to the public for cash in connection with the exercise of the underwriters’ option to purchase additional common units), representing a 20.1% limited partner interest in SMLP, (ii) 24,409,850 subordinated units, representing a 49.0% limited partner interest in SMLP, and (iii) the right to receive $88.0 million in cash as reimbursement for certain capital expenditures made with respect to the contributed assets;

•	pursuant to its long-term incentive plan, SMLP granted 5,000 common units (in the aggregate) to two of its directors and 125,000 phantom units, with distribution equivalent rights, to certain employees;

•	SMLP issued 14,375,000 common units to the public (including 1,875,000 additional common units sold out of the common units originally allocated to Summit Investments) representing a 28.9% limited partner interest in SMLP; and

•

SMLP used the proceeds, net of underwriters’ fees, from the IPO of approximately $269.4 million to (i) repay $140.0 million outstanding under the revolving credit facility; (ii) make cash distributions to Summit Investments of (a) $88.0 million to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us and (b) $35.1 million representing the funds received in connection with the underwriters exercising their option to purchase additional common units; and (iii) pay IPO expenses of approximately $6.3 million.

•	Mountaineer Midstream – the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;

•	Bison Midstream – the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•	DFW Midstream – the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

•	Grand River Gathering – the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah.

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•	Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities;

•

Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and

•	Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

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•

Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services: natural gas gathering, treating and/or processing. Fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at a settled price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The margins earned are directly related to the volume of natural gas that flows through the system.

•

Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs.

•

Keep-Whole. Under keep-whole arrangements, after processing we keep 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, we compensate 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 commodity price exposure for us because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

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•	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.

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•	The acquisition of Bison Midstream occurred on January 1, 2012. The pro forma results for Bison Midstream were derived from revenues and net income in 2013 and 2012.

•	The acquisition of Mountaineer Midstream occurred on January 1, 2012. The pro forma results for Mountaineer Midstream were derived from revenues and net income in 2013. Mountaineer Midstream was not operational until November 2012.

•	The acquisition of Red Rock Gathering occurred on January 1, 2011. The pro forma results for Red Rock Gathering were derived from actual revenues and net income in 2013 and by annualizing the actual operating results for Red Rock Gathering that were recorded in 2012 for the years ended December 31, 2012 and 2011.

•	The acquisition of Grand River Gathering occurred on January 1, 2010. The pro forma results for Grand River Gathering were derived by annualizing the actual operating results for Grand River Gathering that were recorded in 2011.

•	Pro forma net income for the year ended December 31, 2013 has been adjusted to remove the impact of $2.5 million of nonrecurring transaction costs associated with the acquisitions of Bison Midstream and Mountaineer Midstream.

•	Pro forma net income for the year ended December 31, 2012 has been adjusted to remove the impact of $1.6 million of nonrecurring transaction costs associated with the acquisition of Red Rock Gathering.

•	Pro forma net income for the year ended December 31, 2011 has been adjusted to remove the impact of $3.2 million of nonrecurring transaction costs associated with the acquisition of Grand River Gathering.

•

Pro forma adjustments in 2013 and 2012 also reflect the impact of $310.0 million of incremental borrowings on our revolving credit facility for the Bison Midstream and Mountaineer Midstream acquisitions and incremental depreciation and amortization expense associated with the acquired property, plant and equipment and contract intangibles as a result of the application of fair value accounting for Bison Midstream.

•	Pro forma adjustments in 2013, 2012 and 2011 also reflect the combined impact of a 5,300,000 common unit issuance and $100.0 million of incremental borrowings on our revolving credit facility to fund the acquisition of Red Rock Gathering.

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•	Steven J. Newby, President and Chief Executive Officer;

•	Matthew S. Harrison, Senior Vice President and Chief Financial Officer; and

•	Brock M. Degeyter, Senior Vice President, General Counsel and Chief Compliance Officer.

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•	the chairman of the Audit Committee received an additional annual retainer of $15,000;

•	the chairman of the Conflicts Committee received an additional annual retainer of $7,500;

•	each independent member of any committee (other than the chairman) received an additional annual retainer of $1,500; and

•	in connection with the Bison Midstream drop down transaction, in April 2013, we paid the members of the Conflicts Committee fees of $10,000 each for the increased time and effort that they expended in connection with their service on the Conflicts Committee, which reviewed the transaction for fairness to the Partnership and its unitholders.

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