UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

Pursuant to Section 13 OR 15(d)

of The Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported): November 6, 2017

 

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)

 

 

1790 Hughes Landing Blvd

Suite 500

The Woodlands, TX 77380

(Address of principal executive offices) (Zip Code)

 

Registrant's telephone number, including area code: (832) 413-4770

 

Not applicable

(Former name or former address, if changed since last report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

 

 

 

 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

 

 

 

 

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Item 8.01 Other Events.

Summit Midstream Partners, LP ("SMLP" or the “Partnership”) is filing this Current Report on Form 8-K to update certain items in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2016 (the "2016 Annual Report").

 

We evaluate our business operations each reporting period to determine whether any of our gathering system operating segments in which we internally report financial information are considered significant and would require us to separately disclose certain segment financial information in our external reporting. As a result of our evaluation for the quarterly period ended June 30, 2017, we determined that both the Summit Utica natural gas gathering system and the Ohio Gathering natural gas gathering system, each previously reported within the Utica Shale reportable segment, were and are expected to continue to be significant operating segments. As such, we modified our current segments such that the Utica Shale reportable segment includes the Summit Utica gathering system and the Ohio Gathering reportable segment includes our ownership interest in OGC and OCC. The following items of the 2016 Annual Report have been recast to reflect the change in reportable segments:

These items replace the same items filed in the Partnership’s 2016 Annual Report as filed with the Securities and Exchange Commission (the “SEC”) on February 27, 2017. We have not otherwise updated for activities or events occurring after the date these items were originally presented.

 

The information in this Current Report on Form 8-K should be read in conjunction with the other information included (but not replaced as described above) in the 2016 Annual Report. More current information is contained in the Partnership’s Quarterly Reports on Form 10-Q for the quarterly periods ended June 30, 2017 and September 20, 2017 and the Partnership’s other filings with the SEC.

 

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

 

 

 

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EXHIBIT INDEX

 

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

 

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

We consent to the incorporation by reference in Registration Statement Nos. 333-197311, 333-213950, and 333-219196 on Form S-3 and Nos. 333-184214 and 333-189684 on Form S-8 of our report dated February 27, 2017 (November 6, 2017 as to the effects of the segment change as described in Note 3), relating to the consolidated financial statements of Summit Midstream Partners, LP and subsidiaries appearing in this Current Report on Form 8-K of Summit Midstream Partners, LP.

 

/s/ Deloitte & Touche LLP

 

Atlanta, Georgia

November 6, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EX 23.1-1

 

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EXHIBIT 23.1

 

EX 23.1-2

 

EXHIBIT 99.1

 

Item 1. Business.

SMLP is a Delaware limited partnership that completed its IPO in October 2012.  Summit Investments is a Delaware limited liability company and the Predecessor of SMLP for accounting purposes.  References to "we" or "our," when used for dates or periods ended on or after the IPO, refer collectively to SMLP and its subsidiaries.  References to "we" or "our," when used for dates or periods ended prior to the IPO, refer collectively to Summit Investments, as our Predecessor, and its subsidiaries.  For additional information, see Note 1 to the consolidated financial statements.

Item 1. Business is divided into the following sections:

Overview

We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. Our systems gather natural gas from pad sites, wells and central receipt points connected to our systems. Gathered natural gas volumes are then compressed, dehydrated, treated and/or processed for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to third-party rail terminals and pipelines in the case of crude oil and to third-party disposal wells in the case of produced water.  We generally refer to all of the services our systems provide as gathering services.

We are the owner-operator of or have significant ownership interests in the following gathering systems:

 

 

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EXHIBIT 99.1

 

The systems that we operate and/or have a significant ownership interests in have a diverse group of customers and counterparties comprising affiliates and/or subsidiaries of some of the largest crude oil and natural gas producers in North America. Key customers are as follows:

We believe that the systems we operate and/or have significant ownership interests in are positioned for growth through increased utilization and further development. We intend to continue expanding our operations and diversifying our geographic footprint through asset acquisitions from third parties.  We also intend to grow our business through the execution of new, and the expansion of existing, strategic partnerships with large producers to provide midstream services for their upstream exploration and production projects.  In addition, we may participate in asset acquisitions with Summit Investments, although (i) Summit Investments has no current direct ownership interest in any operating assets, (ii) Summit Investments has no obligation to us to offer any assets that it may acquire or participate in any asset acquisitions that we may make and (iii) we have no obligation to acquire those assets.

Our financial results are primarily driven by volume throughput and expense management.  During 2016, aggregate natural gas volume throughput averaged 1,528 MMcf/d and crude oil and produced water volume throughput averaged 88.9 Mbbl/d.  A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk.  Activities that expose us to direct commodity price risk include (i) the sale of processed natural gas and NGLs pursuant to the percent-of-proceeds contracts with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of physical natural gas that we retain from certain of our DFW Midstream system customers to offset a portion of our power expense associated with our electric-drive compression and (iii) the sale of condensate volumes that we retain on the Grand River system.  During the year ended December 31, 2016, we derived less than 9% of our revenues from percent-of-proceeds arrangements and various by-product hydrocarbon sales.

 

 

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EXHIBIT 99.1

 

In addition, the vast majority of our gas gathering and processing agreements include AMIs. Our AMIs cover more than 3.0 million acres in the aggregate, which includes more than 0.7 million acres in Ohio Gathering.  Certain of our gathering and processing agreements also include MVCs. To the extent the customer does not meet its MVC, it must make an MVC shortfall payment to cover the shortfall of required volume throughput not shipped or processed, either on a monthly, quarterly or annual basis. We have designed our MVC provisions to ensure that we will generate a certain amount of revenue from each customer over the life of the associated gathering or processing agreement, whether by collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall.  As of December 31, 2016, we had remaining MVCs totaling 3.1 Tcfe.  Our MVCs have a weighted-average remaining life of 8.1 years (assuming minimum throughput volume for the remainder of the term) and average approximately 1.1 Bcfe/d through 2021.

We use a variety of financial and operational metrics to analyze our performance, including among others, throughput volume, revenues, operation and maintenance expenses and segment adjusted EBITDA.  We view each of these operational and GAAP metrics as important factors in evaluating our profitability and determining the amounts of cash distributions we pay to our unitholders.

For additional information on our results of operations, see Item 6. Selected Financial Data and the "Results of Operations" section included in the Item 7. MD&A, each of which is incorporated herein by reference.

Financial Information About Segments.  As of December 31, 2016, our reportable segments and their respective gathering systems were:

Our reportable segments reflect the way in which (i) we manage our operations and (ii) management uses the reported financial information to make decisions and allocate resources in connection therewith.  The primary assets of our reportable segments consist of gathering systems and the related property, plant and equipment and intangible assets with the exception of the Ohio Gathering reportable segment, which holds our ownership interest in OGC and OCC.

For additional information on our reportable segments, see the "Results of Operations—Segment Overview of the Years Ended December 31, 2016, 2015 and 2014" section included in the Item 7. MD&A and Note 3 to the consolidated financial statements, each of which is incorporated herein by reference.  For additional information on revenue and accounts receivable concentrations, see the "Liquidity and Capital Resources—Credit and Counterparty Concentration Risks" section included in Item 7. MD&A and Notes 3 and 10 to the consolidated financial statements, each of which is incorporated herein by reference.  For additional information on long-lived assets, see Notes 4 and 5 to the consolidated financial statements, each of which is incorporated herein by reference.

 

 

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EXHIBIT 99.1

 

Our Sponsor and Summit Investments.  Energy Capital Partners, together with its affiliated funds, is a private equity firm with over $13.0 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, including investments in the power generation, midstream oil and gas, electric transmission, energy equipment and services, environmental infrastructure and other energy-related sectors.

Summit Investments, which was formed in 2009 by members of our management team and our Sponsor, is the ultimate owner of our General Partner.  We are managed and operated by the Board of Directors and executive officers of our General Partner, which is managed and operated by Summit Investments.  As a result, due to its ownership interest in Summit Investments and its representation on Summit Investments' board of managers, Energy Capital Partners controls our General Partner and its activities, thereby controlling SMLP.

In December 2015, Energy Capital Partners approved a unit purchase program of up to $100.0 million of SMLP common units (the "Purchase Program").  Unit purchases, which commenced in December 2015 and concluded in June 2016, were made in open market transactions and had no impact on the total number of common units outstanding.  Summit Investments acquired 151,160 common units and Energy Capital Partners acquired 5,915,827 common units under the Purchase Program.

Initial Public Offering. SMLP was formed in May 2012 in anticipation of its IPO.  On October 3, 2012, we completed the IPO and the following transactions occurred:

Since the IPO, we have issued additional common units and general partner interests in connection with drop down transactions, one third-party acquisition and certain unit-based compensation awards.  In February 2016, the subordinated units converted to common units on a one-for-one basis.  For additional information, see Notes 1, 11 and 16 to the consolidated financial statements.

Business Strategies

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

 

 

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EXHIBIT 99.1

 

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:

 

 

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EXHIBIT 99.1

 

Our Midstream Assets

Our midstream assets, including assets in which we have a significant ownership interest, currently operate in the following unconventional resource plays:

We compete with other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, service levels, access to end-use markets, geographic proximity of existing assets to a producer's acreage and available capacity. We may also face competition to gather production drilled outside of our AMIs and attract producer volumes to our gathering systems. Additionally, we could face incremental competition to the extent we make acquisitions.

We earn revenue by providing gathering, treating and/or processing services pursuant to primarily long-term and fee-based gathering and processing agreements with some of the largest and most active producers in North America. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

The significant features of our gathering and processing agreements and the gathering systems to which they relate are discussed in more detail below. For additional operating and financial performance information, on a consolidated basis and by reportable segment, see the "Results of Operations" section in Item 7. MD&A, which is incorporated herein by reference.

Areas of Mutual Interest.  The vast majority of our gathering and processing agreements contain AMIs, some of which extend through 2036. The AMIs generally require that any production by our customers within the AMIs will be shipped on and/or processed by our systems.  In general, our customers have not leased acreage that cover our entire AMIs but, to the extent that they lease additional acreage within our AMIs in the future, any production from wells drilled by them within that AMI will be gathered and/or processed by our systems.

Under certain of our gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. However, we may choose not to participate in a discretionary opportunity presented by a customer if we believe that the project would not meet our internal return expectations. Under this scenario, 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, we may release the relevant acreage dedication from the AMI.

Minimum Volume Commitments.  Certain of our gathering and processing agreements contain MVCs, which, like AMIs, benefit the development and ongoing operation of a gathering system because they provide a contracted minimum revenue stream at start up.  As of December 31, 2016, our MVCs, some of which extend through 2026, had a weighted-average remaining life of 8.1 years.  In addition, certain of our customers have an aggregate MVC, which is a total amount of volume throughput that the customer has agreed to ship and/or process on our 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 or processing rate multiplied by the actual throughput volumes shipped or processed.  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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EXHIBIT 99.1

 

For additional information on our MVCs, see the "Critical Accounting Estimates" section in MD&A and Notes 2 and 8 to the consolidated financial statements.

Utica Shale

Summit Utica. In March 2016, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Utica Shale from a subsidiary of Summit Investments.  We refer to these assets as the Summit Utica system. The Summit Utica system is a natural gas gathering system located in the Appalachian Basin in Belmont and Monroe counties in southeastern Ohio and serves producers targeting the dry gas window of the Utica and Point Pleasant shale formations. The system, which includes XTO and Ascent as its key customers, is currently in service and under development and had throughput capacity of 450 MMcf/d as of December 31, 2016.  The Summit Utica system gathers and delivers natural gas, primarily under long-term, fee-based gathering agreements which include acreage dedications. The system interconnects with Energy Transfer Partners, L.P.’s ("Energy Transfer Partners") Utica Ohio River Pipeline, which delivers to the Clarington Hub in Clarington, Ohio.  The Summit Utica system currently provides natural gas midstream services for the Utica Shale reportable segment.

Ohio Gathering

Ohio Gathering.  In March 2016, we acquired substantially all of a 40% ownership interest in Ohio Gathering from a subsidiary of Summit Investments.  Non-affiliated owners have a 60% ownership interest in Ohio Gathering.  Ohio Gathering comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio that is currently in service and under development. The gathering system spans the condensate, liquids-rich and dry gas windows of the Utica Shale for multiple producers that are targeting natural gas, condensate and NGLs production from the Utica and Point Pleasant shale formations across Harrison, Guernsey, Belmont, Noble and Monroe counties in southeastern Ohio.  Gulfport and Ascent are Ohio Gathering's key customers.  Condensate and liquids-rich gas production is gathered, compressed, dehydrated and delivered to the Cadiz and Seneca processing complexes, which are owned by a joint venture between MPLX LP (“MPLX”) and The Energy and Minerals Group (“EMG”).  Dry gas production is gathered, compressed, dehydrated and delivered to a downstream interconnect with Texas Eastern Transmission, or TETCO, and another third-party pipeline, which provides access to the northeast and mid-west markets.  Substantially all gathering services on the Ohio Gathering system are provided pursuant to long-term, fee-based gathering agreements.

The condensate stabilization facility commenced operations in February 2015.  Condensate stabilization allows for producers to capture the NGLs that would otherwise flash from condensate in atmospheric conditions.  As one of the largest stabilization facilities in the Utica Shale Play, this facility serves as the origination point for MPLX’s Cornerstone Pipeline which will deliver condensate to Marathon Petroleum’s refinery in Canton, Ohio.

Our ownership interest in Ohio Gathering is the primary component of the Ohio Gathering reportable segment.  For additional information, see Note 7 to the consolidated financial statements.

Williston Basin

The following table provides operating information regarding our Williston Basin reportable segment as of December 31, 2016.

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(1) Contract terms related to MVCs are presented for liquids and natural gas on a combined basis.

(2) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

AMIs for the Williston Basin reportable segment total more than 1.2 million acres in the aggregate.

 

 

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EXHIBIT 99.1

 

Bison Midstream.  In June 2013, we acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Williston Basin from a subsidiary of Summit Investments.  We refer to these assets as the Bison Midstream system.  The Bison Midstream system is located in Mountrail and Burke counties in northwestern North Dakota.  It consists of low- and high-pressure pipeline and seven compressor stations and includes gathering pipelines ranging from three inches to 10 inches in diameter.  Bison Midstream gathers, compresses and treats associated natural gas that exists in the crude oil stream produced from the Bakken and Three Forks shale formations.  These formations are primarily targeted for crude oil production.  As such, producer drilling and completion activity decisions, and consequently Bison Midstream's volume throughput, are based largely on the prevailing price of crude oil.

Our gathering agreements for the Bison Midstream system include long-term, fee-based or percent-of-proceeds contracts.  Volume throughput on the Bison Midstream system is underpinned by MVCs from its key customers.  In addition to its percent-of-proceeds gathering agreement with Oasis and its fee-based gathering agreement with a large U.S. independent crude oil and natural gas company, the Bison Midstream system is also supported by other fee-based gathering agreements.  Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's Palermo Conditioning Plant in Palermo, North Dakota and then delivered to its 2.1 Bcf/d natural gas processing plant in Channahon, Illinois.  The Bison Midstream system currently provides associated natural gas midstream services for the Williston Basin reportable segment.

Polar and Divide.  In May 2015, we acquired certain crude oil and produced water gathering systems and recently commissioned transmission pipelines in the Williston Basin from a subsidiary of Summit Investments.  In connection with the 2016 Drop Down, we also acquired certain additional crude oil and produced water gathering pipelines.  We refer to these assets, which commenced operations in the second quarter of 2013, as the Polar and Divide system.  The Polar and Divide system, which is located primarily in Williams and Divide counties in northwestern North Dakota, owns, operates and is currently developing crude oil and produced water gathering systems and transmission pipelines serving the Bakken and Three Forks shale formations.

The Polar and Divide system is underpinned by two long-term, fee-based gathering agreements with Whiting and SM Energy. In addition to Whiting and SM Energy, the Polar and Divide system is also supported by other long-term, fee-based gathering agreements and has executed agreements to expand the system to connect additional customer pad sites.

Crude oil that is gathered by the Polar and Divide system is primarily delivered to Crestwood Equity Partners LP's COLT Hub rail facility in Epping, North Dakota and produced water is delivered to third-party disposal facilities located throughout the Williston Basin.  The Polar and Divide system also has interconnects into Enbridge’s North Dakota Pipeline System in Williams County, North Dakota and Global Partners LP's Basin Transload rail terminal in Columbus, North Dakota and has other projects underway to interconnect with additional long-haul take-away pipelines.  The Polar and Divide system currently provides crude oil and produced water midstream services for the Williston Basin reportable segment.

Tioga Midstream.  In March 2016, we acquired certain associated natural gas, crude oil and produced water gathering systems in the Williston Basin from a subsidiary of Summit Investments.  We refer to these assets, which commenced natural gas operations in the fourth quarter of 2014 and liquids operations in the third quarter of 2015, as the Tioga Midstream system.  The Tioga Midstream system is located in Williams County, North Dakota.  All gathering services on the Tioga Midstream system are provided pursuant to long-term, fee-based gathering agreements with Hess, which is primarily targeting crude oil production from the Bakken and Three Forks shale formations.  The gathering agreements underpinning the Tioga system include an annual rate redetermination mechanism which effectively serves to protect future cash flows by resetting the gathering rate upward from pre-established base gathering rates in the event that Hess varies from certain pre-established minimum production thresholds.  The annual rate redeterminations can also reset the gathering rate lower in the event that Hess exceeds the minimum production threshold.  All crude oil, produced water and natural gas gathered on the Tioga Midstream system is delivered to downstream pipelines and disposal wells (for produced water) that are owned and operated by Hess.  The Tioga Midstream system currently provides associated natural gas, crude oil and produced water midstream services for the Williston Basin reportable segment.

 

 

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EXHIBIT 99.1

 

Piceance/DJ Basins

The following table provides operating information regarding our Piceance/DJ Basins reportable segment as of December 31, 2016.

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(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

AMIs for the Piceance/DJ Basins reportable segment total more than 800,000 acres in the aggregate.

Grand River.  In 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin from a third party. We refer to these assets as the Grand River system.  The Grand River system is primarily located in Garfield County, one of the largest natural gas producing counties in Colorado.  It gathers natural gas from the Mesaverde formation and the Mancos and Niobrara shale formations located within the Piceance Basin.

In March 2014, we acquired certain natural gas gathering pipeline, dehydration, compression and processing assets in the Piceance Basin from a subsidiary of Summit Investments.  We refer to these assets as the Red Rock Gathering system, or Red Rock Gathering.  Summit Investments acquired Red Rock Gathering from a subsidiary of Energy Transfer Partners, L.P. in October 2012. Red Rock Gathering gathers and processes natural gas from the Mesaverde formation and the Mancos and Niobrara shale formations located in western Colorado and eastern Utah. Red Rock Gathering is primarily located in Garfield, Rio Blanco and Mesa counties in Colorado and Uintah and Grand counties in Utah.  The Grand River and Red Rock Gathering systems have been connected and are managed as a single system, which we collectively refer to as the Grand River system.

The Grand River system is primarily a low-pressure gathering system that was originally designed to gather natural gas produced from directional wells targeting the liquids-rich Mesaverde formation.  The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling for several decades.  We also gather natural gas from our customers' wells targeting the Mancos and Niobrara shale formations, which underlie the Mesaverde formation, via a medium-pressure gathering system.

Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) Enterprise Product Partners' 1.8 Bcf/d processing facility located in Meeker, Colorado, (ii) Williams Partners L.P.'s Northwest Pipeline and (iii) Kinder Morgan, Inc.'s TransColorado Pipeline system.  Processed NGLs from Grand River are injected into Enterprise's Mid-America Pipeline system or delivered to local markets.  In addition, certain of our gathering agreements with our Grand River customers permit us to retain condensate volumes that naturally discharge from the liquids-rich natural gas as it moves across our system.

The Grand River system has multiple long-term, fee-based gathering agreements with Encana as well as fee-based agreements with Black Hills Exploration and Production, Inc. ("Black Hills") and Terra, both of which include long-term acreage dedications and MVCs.  Certain of the Grand River system's other gathering and processing agreements include MVCs and AMIs.

In 2015, we executed an expansion agreement with a wholly owned subsidiary of Ursa Resources Group II LLC ("Ursa") to provide additional throughput capacity in exchange for new MVCs.  This new capacity will be utilized by Ursa as it executes a drilling plan through 2017.  In connection with the Black Hills gathering agreement, in March 2014 we commissioned a 20 MMcf/d cryogenic processing plant and related gas gathering infrastructure in the DeBeque, Colorado area to support Black Hills' development of its acreage targeting the liquids-rich Mancos and Niobrara formations.  In connection with the Terra gathering agreement, we agreed to expand our gathering and compression services by constructing gas gathering infrastructure in the Rifle, Colorado area.

 

 

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EXHIBIT 99.1

 

We anticipate that the majority of our near-term throughput on the Grand River system will continue to originate from the Mesaverde formation. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize the system's existing throughput capacity.  In addition, we believe that the Grand River system is optimally located for expansion to gather future production from the Mancos and Niobrara shale formations.  The Grand River system currently provides midstream services for the Piceance/DJ Basins reportable segment.

Niobrara G&P.  In March 2016, we acquired certain associated natural gas gathering systems in the DJ Basin from a subsidiary of Summit Investments.  We refer to these assets, which were operational when purchased by Summit Investments, as the Niobrara G&P system.  The system, which is located in Weld County, Colorado, comprises a low-pressure and high-pressure associated natural gas gathering pipeline and cryogenic natural gas processing plant with processing capacity of 20 MMcf/d pursuant to a long-term, fee-based gathering and processing agreement with Fifth Creek and a large U.S. independent crude oil and natural gas company.  Residue gas is delivered to the Colorado Interstate Gas pipeline and processed NGLs are delivered to the Overland Pass Pipeline.  The Niobrara G&P system currently provides midstream services for the Piceance/DJ Basins reportable segment.

Barnett Shale

The following table provides operating information regarding our Barnett Shale reportable segment as of December 31, 2016.

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(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

AMIs for the Barnett Shale reportable segment total more than 120,000 acres.

DFW Midstream.  In 2009 and 2014, we acquired certain natural gas gathering pipeline and compression assets in the Barnett Shale from third parties. We refer to these assets as the DFW Midstream system. The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas.  As 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.  Based on peak month average daily production rates sourced from the Railroad Commission of Texas as of December 2016, this area contains the most prolific wells in the Barnett Shale.  For example, the two largest and five of the 10 largest wells drilled in the Barnett Shale are connected to the DFW Midstream system.

The DFW Midstream system, which includes gathering pipelines ranging from four inches to 30 inches in diameter, is located under both private and public property and is partially located along existing electric transmission corridors.  Compression on the system is powered by electricity.  To offset the costs we incur to operate the system's electric-drive compressors, we either retain a fixed percentage of the natural gas that we gather or pass through a portion of the power expense to our customers.  The DFW Midstream system currently has six primary interconnections with third-party, primarily intrastate pipelines.  These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs in Texas and Louisiana.

The DFW Midstream system is underpinned by a long-term, fee-based gathering agreement with Total and by other long-term, fee-based gathering agreements.  We designed the DFW Midstream system to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the gathering system and, as such, would not require significant additional capital expenditures. Development of the DFW Midstream system has enabled our customers to efficiently produce natural gas by utilizing horizontal drilling techniques from pad sites already connected in our AMIs. Given the urban nature of southeastern Tarrant County, we expect that the majority of future natural gas drilling in this area will occur from existing pad site locations.  The DFW Midstream system currently provides midstream services for the Barnett Shale reportable segment.

 

 

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EXHIBIT 99.1

 

Marcellus Shale

The following table provides operating information regarding our Marcellus Shale reportable segment as of December 31, 2016.

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(1) Contract terms related to AMIs and MVCs are excluded for confidentiality purposes.

Mountaineer Midstream.  In June 2013, we acquired certain high-pressure natural gas gathering pipelines and compression assets located in the liquids-rich window of the Marcellus Shale Play from an affiliate of MarkWest Energy Partners, L.P. (“MarkWest,” which was subsequently acquired by MPLX). We refer to these assets as the Mountaineer Midstream system.  This system, which operates in the Appalachian Basin, benefits from its location in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term, fee-based contract with Antero. The Mountaineer Midstream system consists of newly constructed, high-pressure natural gas gathering pipelines ranging from eight inches to 20 inches in diameter and two compressor stations. This liquids-rich natural gas gathering and compression system serves as a critical inlet to MPLX's Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia, which provides downstream access to Midwest, mid-Atlantic and northeast regions of the United States.

In November 2013, we amended our original fee-based natural gas gathering agreement with Antero whereby we agreed to construct approximately nine miles of high-pressure, 20-inch pipeline on the Mountaineer Midstream system (the "Zinnia Loop").  The Zinnia Loop, which was commissioned in 2014, is underpinned by a minimum revenue commitment from Antero and increased throughput capacity to 1,050 MMcf/d to support Antero's drilling activities.  The Mountaineer Midstream system currently provides midstream services for the Marcellus Shale reportable segment.

For additional information relating to our business and gathering systems, see the "Trends and Outlook" and "Results of Operations" sections in Item 7. MD&A.

Regulation of the Natural Gas and Crude Oil Industries

General.  Sales by producers of natural gas, crude oil, condensate and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which 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 is also authorized to prevent and sanction market manipulation in natural gas markets while the FTC is authorized to prevent and sanction market manipulation in petroleum markets. 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 Crude 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, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. 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 its 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.

 

 

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EXHIBIT 99.1

 

Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers' ability to produce natural gas.

Regulation of the Gathering and Transportation of Natural Gas and Crude Oil.  We believe that the majority of our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC.  On February 1, 2016, Polar Midstream's FERC tariff for interstate movements of crude oil on its Little Muddy pipeline in North Dakota became effective. That tariff is subject to FERC jurisdiction and oversight pursuant to FERC's authority under the ICA.  We are also generally subject to FERC's anti-market manipulation regulations. The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and changes in the policies and interpretations of laws and regulations.  In addition, the status of any individual pipeline system 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 pipeline systems (including some of our pipelines) could change based on future determinations by FERC or the courts.

Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the DOT, although typically state regulatory authorities (operating under a federal certification) perform this function.  State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, 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 are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file tariffs in the other states in which we operate, although we are required to submit shape files and other information regarding the location and construction of underground gathering pipelines in North Dakota. The states in which we operate 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 in the states in which we operate generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint.  State regulation of intrastate pipelines continues to evolve and may become more stringent in the future.  For example, the North Dakota Industrial Commission recently adopted rule changes that resulted in additional construction and monitoring requirements for all pipelines, including, but not limited to, those that transport produced water, and has recently adopted reclamation bonding requirements for certain underground gathering pipelines in North Dakota.

Natural gas, crude oil and produced water production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements.

Anti-Market Manipulation Rules.  We are subject to the anti-market manipulation provisions in the NGA and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to $1,000,000 per day per violation of the NGA, the NGPA, or their implementing regulations. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 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 in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

 

 

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EXHIBIT 99.1

 

Safety and Maintenance.  We are subject to regulation by the DOT, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas and crude oil pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the DOT's regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas.  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.

The DOT has delegated the implementation of safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than 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 currently exempt from the integrity management requirements of PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to:

In October 2015, PHMSA proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management requirements.  PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations.  PHMSA recently adopted regulations that impose pipeline incident prevention and response measures on pipeline operators.  PHMSA has also issued an Advisory Bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure.  Pipelines that do not meet PHMSA’s record verification standards may be required to perform additional testing or reduce their operating pressures.

Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act 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 Occupational Safety and Health Administration 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 the public.

 

 

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EXHIBIT 99.1

 

Environmental Matters

General.  Our operation of pipelines and other assets for the gathering, treating and/or processing of natural gas and the gathering of crude oil and produced water 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 assets, 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:

Failure to comply with these laws and regulations may trigger 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 stringent requirements, resulting in 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 and future regulations.

The following is a discussion of the material environmental laws and regulations that relate to our business.

Hazardous Substances and Waste.  Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including 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. Furthermore, the Toxic Substances Control Act and analogous state laws, impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.  CERCLA 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 RCRA and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Although we generate minimal hazardous waste, 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.

 

 

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EXHIBIT 99.1

 

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators 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, without our knowledge.  These properties and the wastes disposed thereon may be subject to CERCLA, the 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.

Air Emissions.  Our operations are subject to the federal CAA and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring, control 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 criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources.

In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 parts per billion ("ppb"). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate, which could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs.  Impacts from the new standard have not yet been determined, as states are still in the process of incorporating the new standard into their respective state implementation plans. We will continue to monitor developments to determine if any adverse effects on our operations can be expected.

On June 3, 2016, the EPA finalized revisions to its 2012 New Source Performance Standard ("NSPS") OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. The revised rule applies to sources that have been modified, constructed, or reconstructed after September 18, 2015. While we do not expect this rule to significantly impact our existing operations, future modifications or new construction may be adversely affected by the revised rule.

On November 16, 2016 the Bureau of Land Management ("BLM") issued a final rule to reduce venting and flaring of natural gas on public and Indian lands. The final rule mirrors many of the requirements found in NSPS OOOOa, with additional natural gas royalty requirements for flared volumes at sites already connected to gas capture infrastructure. While the rule is expected to have little or no direct impact on our operations, our customers that are primarily upstream wellhead operators may be impacted by the requirements in this rule.

Water Discharges.  The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters, which impacts 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. 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 require us to control storm water runoff from some 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.

 

 

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EXHIBIT 99.1

 

Oil Pollution Act.  The OPA requires the preparation of an SPCC plan 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. Certain of our facilities are classified as SPCC-regulated facilities.  We believe that they are in substantial compliance with all applicable requirements of OPA.

Hydraulic Fracturing. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily presently regulated by state agencies. However, Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing and are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on oil and/or natural gas drilling activities. The EPA is also moving forward with various related regulatory actions, including approving new regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements that went into effect in 2015.  Revisions to the green completion regulations were finalized in June 2016 and include additional requirements to reduce methane and VOCs.  We do not believe these new regulations will have a direct effect on our operations, but because natural gas and/or crude oil production using hydraulic fracturing is growing rapidly in the United States, if new or more stringent federal, state or local legal restrictions relating to such drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil.

Endangered Species Act.  The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species.

National Environmental Policy Act.  The 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. Major projects having the potential to significantly impact the environment require review under NEPA. Many of our activities are covered under categorical exclusions which results in an expedited NEPA review process. Large upstream and downstream projects with significant cumulative impacts may be subject to longer NEPA review processes, which could impact the timing of those projects and our services associated with them.

Climate Change.  The EPA has adopted regulations under the CAA that, among other things, establish GHG emission limits from motor vehicles as well as establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.

EPA rules also require the reporting of GHG emissions from specified large GHG-emitting sources in the United States, including onshore and offshore oil and natural gas systems. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. In October 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines, and completions and workovers of oil wells with hydraulic fracturing.  This development will result in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services.

 

 

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EXHIBIT 99.1

 

The EPA continues to consider additional climate change requirements for the energy industry. On November 10, 2016, the EPA issued an Information Collection Request ("ICR") under Section 114 of the CAA to gather and evaluate source specific information from the oil and natural gas sector. The information will be used to potentially draft new regulations to reduce methane emissions from existing sources not currently covered by the NSPS under subparts OOOO and OOOOa. It is unclear what impact this Information Collection Request will have on future methane rulemakings, and changes in political administration may impact whether this information is used for any future methane rulemakings, as well as enforcement, development, and implementation of climate change requirements generally.  We will continue to monitor such developments to determine if they will impact our operations.

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 certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016, after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement.

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 GHG-emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. Conversely, to the extent that our products are competing with lower GHG-emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions.

Other Information

Employees. SMLP does not have any employees. All of the employees required to conduct and support its operations are employed by Summit Investments, but these individuals are sometimes referred to as its employees. The officers of our General Partner manage our operations and activities. As of December 31, 2016, Summit Investments employed 331 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have never experienced any business interruption as a result of any labor disputes.

Availability of Reports. We make certain filings with the SEC, including, among other filings, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The filings are also available at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549 or by calling 1-800-SEC-0330. These filings are also available through the SEC's website, www.sec.gov. Our press releases and recent investor presentations are also available on our website.

 

 

EXHIBIT 99.2

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries. As a result, the following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements.  Actual results may differ materially from those contained in any forward-looking statements.

This MD&A comprises the following sections:

Overview

We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. We are the owner-operator of or have significant ownership interests in the following gathering systems:

EX 99.2-1

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EXHIBIT 99.2

 

For additional information on our organization and systems, see Notes 1 and 3 to the consolidated financial statements.

Our financial results are driven primarily by volume throughput and expense management.  We generate the majority of our revenues from the gathering, treating and processing services that we provide to our customers.  A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk.  We also earn revenues from (i) the sale of physical natural gas and NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River.  These additional activities, which expose us to direct commodity price risk, accounted for less than 9% of total revenues during the year ended December 31, 2016.

We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs ensure that we will recognize a minimum amount of revenue.

The following table presents certain annual consolidated financial data.

 

 

(1)  Reflects cash and noncash consideration, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs (see Notes 11 and 16 to the consolidated financial statements).

(2)  See "Liquidity and Capital Resources" herein and Note 3 to the consolidated financial statements for additional information on capital expenditures.

(3)  Reflects proceeds from underwritten primary offerings.

Year ended December 31, 2016.  The following items are reflected in our financial results:

EX 99.2-2

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EXHIBIT 99.2

 

Year ended December 31, 2015.  The following items are reflected in our financial results:

Year ended December 31, 2014.  The following items are reflected in our financial results:

EX 99.2-3

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EXHIBIT 99.2

 

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:

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, NGL and crude oil supply and demand dynamics.  Natural gas continues to be a critical component of energy supply and demand in the United States. The price of natural gas rebounded during 2016, with the New York Mercantile Exchange, or NYMEX, natural gas futures price at $3.71 per one million British Thermal Units ("MMBtu") as of December 30, 2016, compared with $2.28 per MMBtu as of December 31, 2015.  Despite the significant increase, natural gas prices continue to trade at lower-than-average historical prices due in part to increased natural gas production and the amount of natural gas in storage in the continental United States.  In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely to remain constrained.  Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Similar to natural gas prices, crude oil prices increased significantly during 2016, with the West Texas Intermediate ("WTI") crude oil price benchmark increasing by 105% from February to December of 2016, when it closed at $53.75 per barrel.  In response to the increase in crude oil prices, the number of active crude oil drilling rigs in the continental United States increased from a low of 316 in May 2016 to 525 in December 2016, according to Baker Hughes.  Over the next several years, we expect that crude oil prices will rebound sufficiently to support continued drilling and increasing production in the Bakken Shale, Eagle Ford Shale, Permian Basin and Niobrara Shale.

Growth in production from U.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased significantly due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays.  In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance Basin, Barnett, Bakken, Marcellus and Utica shale plays in which we operate, and we believe that these long-term capital investments will support sustained drilling activity in unconventional shale plays.

EX 99.2-4

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EXHIBIT 99.2

 

Capital markets availability and cost of capital.  Credit markets improved substantially throughout 2016, as borrowing costs were lower relative to the levels generally experienced during the 2008 global financial crisis for virtually all energy industry-related borrowers. The credit market trends in the crude oil and natural gas industry during 2016 were unique relative to the broader economy. While borrowing costs came down for the oil and natural gas industry as a whole, the Federal Reserve announced that it raised its benchmark federal-funds rate from 0.25% and 0.50% to a range between 0.50% and 0.75% in December 2016. The Federal Reserve also announced its intent to continue to raise interest rates gradually in the future, to the extent that economic growth continues.  Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt capital markets to the extent necessary to fund our future 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 debt capital on acceptable terms, we expect to remain competitive with respect to acquisitions and capital projects, as our peers and competitors would likely face similar circumstances.

Shifts in operating costs and inflation.  Throughout most of the last five years, high levels of crude oil and natural gas exploration, development and production activities across the United States resulted in increased competition for personnel and equipment as well as higher prices for labor, supplies, equipment and other services. Beginning in 2015, this dynamic began to shift as prices for crude oil and natural gas-related services decreased in line with overall decline in demand for these goods and services.  While we expect lower service-related costs in the near term, we expect that over the longer term, these costs will continue to have a high correlation to changes in the prevailing price of crude oil and natural gas.

How We Evaluate Our Operations

We conduct and report our operations in the midstream energy industry through six reportable segments:

Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 3 to the consolidated financial statements).

Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and determining the amounts of cash distributions to pay to our unitholders. These metrics include:

Throughput Volume

The volume of (i) natural gas that we gather, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.

EX 99.2-5

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EXHIBIT 99.2

 

As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of throughput is impacted by:

We report volumes gathered for natural gas in cubic feet per day.  We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day.

Revenues

Our revenues are primarily attributable to the volumes that we gather, treat and/or process and the rates we charge for those services. A substantial majority of our gathering and processing agreements are fee-based, which limits our direct commodity price exposure. We also have percent-of-proceeds arrangements under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs.

Many of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs support our revenues and serve to mitigate the financial impact associated with declining volumes.

Operation 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 our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.

Segment Adjusted EBITDA

Segment adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others.

Segment adjusted EBITDA is used to assess:

EX 99.2-6

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EXHIBIT 99.2

 

Items Affecting the Comparability of Our Financial Results

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

Additional Information.  For additional information, see the "Results of Operations" section herein and the notes to the consolidated financial statements.  For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the consolidated financial statements.

Results of Operations

Our financial results are recognized as follows:

Gathering services and related fees.  Revenue earned from the gathering, treating and processing services that we provide to our natural gas and crude oil producer customers.

Natural gas, NGLs and condensate sales.  Revenue earned from (i) the sale of physical natural gas and NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services on the Grand River system.

Other revenues.  Revenue earned primarily from (i) certain costs for which our Bison Midstream and Grand River customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system.

Cost of natural gas and NGLs.  The cost of natural gas and NGLs represents the costs associated with the percent-of-proceeds arrangements under which we sell natural gas and NGLs purchased from certain of our customers on the Bison Midstream and Grand River systems.

Operation and maintenance.  Operation and maintenance primarily comprises direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services.  These items represent the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of variations in throughput volumes but may fluctuate depending on the activities performed during a specific period.

General and administrative.  Expenses associated with our operations that are not specifically associated with the operation and maintenance of a particular system or another cost and expense line item. These expenses largely reflect salaries, benefits and incentive compensation, professional fees, insurance and rent.

EX 99.2-7

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EXHIBIT 99.2

 

Depreciation and amortization.  The depreciation of our property, plant and equipment and the amortization of our contract and right-of-way intangible assets.

Transaction costs.  Financial and legal advisory costs associated with completed acquisitions.

Other income or expense.  Generally represents other items of gain or loss but may also include interest income.

Interest expense.  Interest expense associated with our Revolving Credit Facility, our Senior Notes and debt that was previously incurred by SMP Holdings and allocated to SMLP in connection with the 2016 Drop Down.

Deferred Purchase Price Obligation expense.  Represents the expense associated with the Deferred Purchase Price Obligation.

Income tax expense or benefit.  Represents the expense or benefit associated with the Texas Margin Tax.

Income or loss from equity method investees.  Represents the income or loss associated with our ownership interest in Ohio Gathering.

Consolidated Overview of the Years Ended December 31, 2016, 2015 and 2014

The following table presents certain consolidated and operating data for the years ended December 31.

 

 

* Not considered meaningful

EX 99.2-8

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EXHIBIT 99.2

 

Volumes – Gas.  Natural gas throughput volumes increased 29 MMcf/d during the year ended December 31, 2016, as compared to the prior year, primarily reflecting:

Natural gas throughput volumes increased 76 MMcf/d during the year ended December 31, 2015, as compared to the prior year, primarily reflecting:

Volumes – Liquids.  Crude oil and produced water throughput volumes increased 21.2 Mbbl/d during the year ended December 31, 2016, primarily reflecting the continued development of the Polar and Divide and Tioga Midstream systems, new pad site connections and producers' ongoing drilling activity, partially offset by the second quarter 2016 impact of certain customers shutting in existing production while completion activities occurred.

Crude oil and produced water throughput volumes increased 27.0 Mbbl/d during the year ended December 31, 2015, primarily reflecting the continued development of the Polar and Divide and Tioga Midstream systems, new pad site connections and producers' ongoing drilling activity, partially offset by the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained volume throughput in the first nine months of 2015 (see Note 15 to the consolidated financial statements).

Revenues.  Total revenues increased $1.8 million, or 0.5%, during the year ended December 31, 2016, as compared to the prior year, primarily reflecting:

Total revenues increased $13.4 million, or 3%, during the year ended December 31, 2015, as compared to the prior year, primarily reflecting:

Gathering Services and Related Fees.  The increase in gathering services and related fees during the year ended December 31, 2016 primarily reflected:

EX 99.2-9

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EXHIBIT 99.2

 

The increase in gathering services and related fees during the year ended December 31, 2015 primarily reflected:

Natural Gas, NGLs and Condensate Sales.  The decrease in natural gas, NGLs and condensate sales during the year ended December 31, 2016 primarily reflected the impact on pricing and throughput of lower commodity prices on our Williston Basin, Piceance/DJ Basins and Barnett Shale segments, which in turn impacted volume throughput as well as the associated sales, during the first half of 2016.

The decrease in natural gas, NGLs and condensate sales during the year ended December 31, 2015 was primarily a result of the impact on pricing and throughput of declining commodity prices during 2015 on our Williston Basin, Piceance/DJ Basins and Barnett Shale segments.

Commodity prices and changes therein have a direct impact on our percent-of-proceeds arrangements for the Bison Midstream and Grand River systems, our fuel retainage revenue for the DFW Midstream system and condensate revenue for the Grand River system.

Costs and Expenses.  Total costs and expenses decreased $267.2 million, or 48%, for the year ended December 31, 2016, as compared to the prior year, primarily reflecting:

Total costs and expenses increased $188.2 million, or 51%, for the year ended December 31, 2015, as compared to the prior year, primarily reflecting:

EX 99.2-10

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EXHIBIT 99.2

 

Cost of Natural Gas and NGLs.  The decrease in cost of natural gas and NGLs during the year ended December 31, 2016 largely reflected the impact on pricing and throughput of lower comparative commodity prices on our Williston Basin and Piceance/DJ Basins segments during the first half of 2016 and the associated impact on (i) our percent-of-proceeds arrangements for the Bison Midstream system and (ii) our percent-of-proceeds arrangements and condensate sales for the Grand River system.

The decrease in cost of natural gas and NGLs for the year ended December 31, 2015 largely reflected the impact on pricing and throughput of declining commodity prices on our Williston Basin and Piceance/DJ Basins segments and the associated impact on our percent-of-proceeds arrangements for the Bison Midstream and Grand River systems.

Operation and Maintenance.  Operation and maintenance expense increased during the year ended December 31, 2016 primarily reflecting (i) overall increases for Utica Shale and Williston Basin segments, primarily as a result of the development of the Summit Utica, Tioga Midstream and Polar and Divide systems and (ii) an increase for the Marcellus Shale segment for expenses associated with repairs to rights-of-ways on the Mountaineer Midstream system.  The impact of these items was partially offset by declines for the Piceance/DJ Basins and Barnett Shale segments.

Operation and maintenance expense increased during the year ended December 31, 2015 primarily reflecting an environmental remediation accrual for assets contributed to Polar and Divide, an increase in connection fee pass-through expense for Polar and Divide as a result of increased volumes (revenue component is recognized in other revenues), an increase in property taxes and an increase in compensation expense.  These increases were partially offset by volume-driven declines in electricity expense associated with DFW Midstream's electric-drive compression assets and a decline in pass-through electricity expense for Grand River (revenue component is recognized in other revenues.)

General and Administrative.  General and administrative expense increased during the year ended December 31, 2016 primarily reflecting an increase in expenses for salaries, benefits and incentive compensation.

General and administrative expense increased during the year ended December 31, 2015 reflecting an increase in salaries, benefits and incentive compensation and an increase in rent expense.  These increases were partially offset by a decline in professional services, primarily the result of expenses incurred in 2014 in connection with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO 2013").

Depreciation and Amortization.  The increase in depreciation and amortization expense during 2016 and 2015 was largely driven by an increase in assets placed into service.

Transaction Costs.  Transaction costs recognized during the year ended December 31, 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.  Transaction costs recognized during the year ended December 31, 2015 primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down.  Transaction costs recognized during the year ended December 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down.  Transaction costs in 2015 and 2014 also include financial and legal advisory expenses incurred by Summit Investments for third-party acquisitions that were allocated to us in connection with the 2016 Drop Down.

Interest Expense.  The increase in interest expense during the year ended December 31, 2016 was primarily driven by (i) higher costs associated with increased borrowings on our Revolving Credit Facility and (ii) debt incurred by Summit Investments that was allocated to the Partnership in connection with the 2016 Drop Down.  The Revolving Credit Facility borrowings incurred in March 2016 in connection with funding a portion of the 2016 Drop Down purchase price replaced the lower-rate Summit Investments' debt that had been allocated to us prior to our March 2016 closing of the 2016 Drop Down, resulting in an increase in interest expense.

EX 99.2-11

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EXHIBIT 99.2

 

The increase in interest expense during the year ended December 31, 2015 was primarily driven by our July 2014 issuance of the 5.5% Senior Notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

Deferred Purchase Price Obligation Expense.  Deferred Purchase Price Obligation expense recognized in 2016 relates to our March 2016 issuance of the deferred payment in connection with the 2016 Drop Down (see Notes 2 and 16 to the consolidated financial statements).

For additional information, see the "Segment Overview of the Years Ended December 31, 2016, 2015 and 2014" and "Corporate and Other Overview of the Years Ended December 31, 2016, 2015 and 2014" sections herein.

Segment Overview of the Years Ended December 31, 2016, 2015 and 2014

Utica Shale.  The Utica Shale reportable segment includes the Summit Utica system, which was acquired from a subsidiary of Summit Investments in March 2016.

Volume throughput for our Summit Utica system follows.

 

 

* Not considered meaningful

(1) For the period of SMLP's ownership in 2014, average throughput was 12 MMcf/d.

 

Volume throughput increased in 2016 and 2015 due to our continued buildout of the Summit Utica system and our customer's commissioning of new wells throughout 2015 and into 2016.

 

Financial data for our Utica Shale reportable segment follows.

 

 

* Not considered meaningful

 

Year ended December 31, 2016.  Segment adjusted EBITDA increased $18.8 million during 2016 primarily reflecting the growth and development of the Summit Utica system.

Depreciation and amortization increased over 2015 as a result of placing assets into service at the Summit Utica system.

EX 99.2-12

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EXHIBIT 99.2

 

Year ended December 31, 2015.  Segment adjusted EBITDA increased $2.0 million during 2015 primarily reflecting a full year of operations in 2015 as well as the growth and development of the Summit Utica system.

Depreciation and amortization increased over 2014 as a result of placing assets into service at the Summit Utica system.

Ohio Gathering.  The Ohio Gathering reportable segment includes Ohio Gathering which was acquired from a subsidiary of Summit Investments in March 2016.

Gross volume throughput for Ohio Gathering, based on a one-month lag follows.

 

 

Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.

 

 

* Not considered meaningful

Year ended December 31, 2016.  Segment adjusted EBITDA increased $11.9 million during 2016 primarily reflecting an increase in our proportional share of Ohio Gathering's adjusted EBITDA primarily due to growth and development in the first half of 2016.  Volume growth decelerated for both OGC and OCC beginning in the third quarter of 2016 thereby slowing the year-over-year overall increase.

Year ended December 31, 2015.  Segment adjusted EBITDA increased $27.7 million during 2015 primarily reflecting an increase in our proportional share of Ohio Gathering's adjusted EBITDA due to ongoing growth and development.

Williston Basin.  The Bison Midstream, Polar and Divide and Tioga Midstream systems provide our midstream services for the Williston Basin reportable segment.  Polar and Divide was acquired from subsidiaries of Summit Investments in May 2015, with additional assets that currently comprise a portion of the Polar and Divide system, subsequently acquired from Summit Investments in March 2016.  Tioga Midstream was acquired from a subsidiary of Summit Investments in March 2016.  Our results include activity for (i) the Bison Midstream and Polar and Divide systems for all periods presented and (ii) the Tioga Midstream system since April 2014.

Operating data for our Williston Basin reportable segment follows.

 

Liquids.  The increase in liquids volume throughput during 2016 reflects the completion of new wells across our gathering footprint and the connection of pad sites that had been previously using third-party trucks to gather crude oil and/or produced water.  In addition, the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained 2015 volume throughput.

The increase in liquids volume throughput in 2015 reflect new pad site connections and ongoing drilling activity in the Polar and Divide system's service area.

EX 99.2-13

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EXHIBIT 99.2

 

Natural gas.  Natural gas volume throughput remained flat during 2016 largely reflecting the offsetting effects of the growth of the Tioga Midstream system throughout 2015 and into the first quarter of 2016 and lower volume throughput on the Bison Midstream system.

Natural gas volume throughput increased in 2015 due to growth on the Tioga Midstream system and increases in gas-to-oil ratios on existing production.  This effect was partially offset by the effects of customers reducing their drilling activities in response to continued declines in commodity prices.

Financial data for our Williston Basin reportable segment follows.

 

 

* Not considered meaningful

Year ended December 31, 2016.  Segment adjusted EBITDA increased $45.5 million during 2016 primarily reflecting:

EX 99.2-14

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EXHIBIT 99.2

 

Other items to note:

Year ended December 31, 2015.  Segment adjusted EBITDA increased $4.0 million during 2015 primarily reflecting:

Other items to note:

Piceance/DJ Basins. The Grand River system provides midstream services for the Piceance/DJ Basins reportable segment.  The Red Rock Gathering system was acquired from a subsidiary of Summit Investments in March 2014.  Niobrara G&P was acquired from a subsidiary of Summit Investments in March 2016.  Our results include activity for the Grand River, Red Rock Gathering and Niobrara G&P systems for all periods presented.

Operating data for our Piceance/DJ Basins reportable segment follows.

 

Volume throughput decreased during 2016 primarily as a result of the continued suspension of drilling activities by one of Grand River's key customers and the resulting natural declines from existing production.  The impact of these decreases was partially offset by an increase in volume throughput by other producer customers.

EX 99.2-15

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EXHIBIT 99.2

 

Volume throughput declined during 2015 primarily as a result of the suspension of drilling activities by one of Grand River's key customers and the resulting natural declines from existing production.  The impact of these factors was partially offset by volume throughput from new pad site connections for WPX (subsequently acquired by Terra) and Ursa Resources Group II as well as the March 2014 start-up of a cryogenic processing plant servicing production from Black Hills Corporation.

Financial data for our Piceance/DJ Basins reportable segment follows.

 

 

* Not considered meaningful

Year ended December 31, 2016.  Segment adjusted EBITDA decreased $1.0 million during 2016 primarily reflecting:

Other items to note:

EX 99.2-16

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EXHIBIT 99.2

 

Year ended December 31, 2015.  Segment adjusted EBITDA decreased $0.5 million during 2015 primarily reflecting:

Other items to note:

Barnett Shale.  The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment. In September 2014, DFW Midstream acquired certain natural gas gathering assets (the "Lonestar assets") from a third party.  Our results include activity for (i) the DFW Midstream system for all periods presented and (ii) the Lonestar assets since September 2014.

Operating data for our Barnett Shale reportable segment follows.

 

Volume throughput declined during 2016 reflecting reduced drilling and completion activity, together with natural production declines, partially offset by the commissioning of an 11-well pad site in the second quarter of 2016 and the commissioning of 14 wells in December 2015 and January 2016.

EX 99.2-17

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EXHIBIT 99.2

 

Volume throughput was relatively flat during 2015 reflecting several offsetting effects related to customer drilling and completion activities, the contribution from the Lonestar assets beginning in the fourth quarter of 2014 and a lack of drilling activity by DFW Midstream's then-key customer, Chesapeake.

Financial data for our Barnett Shale reportable segment follows.

 

 

*Not considered meaningful

Year ended December 31, 2016.  Segment adjusted EBITDA decreased $4.9 million during 2016 primarily reflecting:

Other items to note:

EX 99.2-18

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EXHIBIT 99.2

 

Year ended December 31, 2015.  Segment adjusted EBITDA decreased $1.0 million during 2015 primarily reflecting:

The long-lived asset impairments in 2015 and 2014 reflect our decisions to impair certain property, plant and equipment balances associated with the decommissioning of certain assets.  These impairments had no impact on segment adjusted EBITDA for the years ended December 31, 2015 or 2014.

Marcellus Shale.  The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment.

Volume throughput for the Marcellus Shale reportable segment follows.

 

Volume throughput declined during 2016 due to natural production declines which were not offset by new production as a result of Antero's decision to defer completion activities in the third quarter of 2015.  Volume throughput during 2016 was also impacted by repairs on a third-party NGL pipeline located downstream of the Sherwood Processing Complex in June and July 2016 limiting the amount of natural gas we could deliver during the repair work.

The increase in volume throughput in 2015 was primarily driven by Antero's connection of new wells located upstream of the Mountaineer Midstream system.

Financial data for our Marcellus Shale reportable segment follows.

 

EX 99.2-19

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EXHIBIT 99.2

 

Year ended December 31, 2016.  Segment adjusted EBITDA decreased $4.0 million during 2016 primarily reflecting:

Year ended December 31, 2015.  Segment adjusted EBITDA increased $7.3 million during 2015 primarily reflecting:

Depreciation and amortization increased during 2015 largely as a result of commissioning the Zinnia Loop project late in the third quarter of 2014.

Corporate and Other Overview of the Years Ended December 31, 2016, 2015 and 2014

Corporate and other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, interest expense and Deferred Purchase Price Obligation income or expense. Items to note follow.

 

 

*  Not considered meaningful

(1) Includes interest expense on debt allocated to the 2016 Drop Down Assets during the common control period (see Note 2 to the consolidated financial statements).

General and Administrative.  In the first quarter of 2015, the Partnership discontinued allocating certain administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to its then-reportable segments.  As a result, the amount of expense allocated to and reported within the Company’s operating segments decreased, with a commensurate increase in corporate general and administrative expenses.  This change, however, did not impact the historical results of entities under common control which were acquired subsequent to the first quarter of 2015.  As a result, general and administrative expense allocations were higher for Polar and Divide and the 2016 Drop Down Assets during their respective common control periods because Summit Investments continued to allocate these administrative expenses to its non-Partnership subsidiaries.  With respect to Polar and Divide, general and administrative expense allocations during the period from January 1, 2014 to May 18, 2015 included items that SMLP was no longer allocating to its then-operating segments.  With respect to the 2016 Drop Down Assets, general and administrative expense allocations during the period from January 1, 2014 to March 3, 2016 included items that SMLP was no longer allocating to its then-operating segments.  As such, subsequent to a given drop down, the application of the new expense allocation methodology to the newly acquired

EX 99.2-20

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EXHIBIT 99.2

 

entities resulted in a decrease in reportable segment general and administrative expenses and an increase in corporate general and administrative expenses.

The increase in general and administrative expenses during the years ended December 31, 2016 primarily reflects the impact of a change in our expense allocation methodology and an increase in salaries, benefits and incentive compensation.

The increase in general and administrative expenses during the year ended December 31, 2015 primarily reflects the impact of a change in our expense allocation methodology.  The increase was also a result of an increase in salaries, benefits and incentive compensation and rent expense.  These increases were partially offset by a decline in professional services, primarily the result of expenses incurred in 2014 in connection with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of COSO 2013.

Transaction Costs.  Transaction costs recognized during the year ended December 31, 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.  Transaction costs recognized during the year ended December 31, 2015 primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down.  Transaction costs recognized during the year ended December 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down.  Transaction costs in 2015 and 2014 also include financial and legal advisory expenses incurred by Summit Investments for third-party acquisitions that were allocated to us in connection with the 2016 Drop Down.

Interest Expense. The increase in interest expense during the year ended December 31, 2016 was primarily driven by (i) higher costs associated with increased borrowings on our Revolving Credit Facility and (ii) debt incurred by Summit Investments that was allocated to the Partnership in connection with the 2016 Drop Down.  The Revolving Credit Facility borrowings incurred in March 2016 in connection with funding a portion of the 2016 Drop Down purchase price replaced the lower-rate Summit Investments' debt that had been allocated to us prior to our March 2016 closing of the 2016 Drop Down, resulting in an increase in interest expense.

The increase in interest expense during the year ended December 31, 2015 was primarily driven by our July 2014 issuance of the 5.5% Senior Notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

Deferred Purchase Price Obligation Expense.  Deferred Purchase Price Obligation expense recognized in 2016 relates to our March 2016 issuance of the deferred payment in connection with the 2016 Drop Down (see Notes 2 and 16 to the consolidated financial statements).

Liquidity and Capital Resources

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 flows generated from our operations, borrowings under our Revolving Credit Facility and future issuances of equity and debt instruments.

Capital Markets Activity

November 2016 Shelf Registration Statement.  In October 2016, we filed the 2016 SRS and in November 2016, the SEC declared it effective.  The following transaction has been executed pursuant thereto:

Following the January 2017 secondary offering, we can issue up to $1.50 billion of debt and equity securities in primary offerings and a total of 32,701,230 common units held by (i) a subsidiary of Summit Investments and (ii) affiliates of our Sponsor pursuant to the 2016 SRS.  The 2016 SRS expires in November 2019.

EX 99.2-21

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EXHIBIT 99.2

 

July 2014 Shelf Registration Statement.  In July 2014, we filed the 2014 SRS with the SEC to issue an unlimited amount of debt and equity securities and shortly thereafter completed a public offering of $300.0 million aggregate principal 5.5% senior unsecured notes due 2022.  We used the proceeds to repay a portion of the outstanding borrowings under our Revolving Credit Facility.

In February 2017, we amended the 2014 SRS to include additional guarantor subsidiaries and completed a public offering of $500.0 million principal 5.75% senior unsecured notes due 2025.  Concurrent therewith, we made a tender offer to purchase all of the outstanding 7.5% Senior Notes.  The tender offer expired on February 14, 2017 with $276.9 million validly tendered.   On February 16, 2017, we issued a notice of redemption for the 7.5% Senior Notes that remained outstanding subsequent to the tender offer.  The remaining 7.5% Senior Notes will be redeemed on March 18, 2017, with payment made on March 20, 2017.  In addition to using the proceeds to purchase all of the outstanding 7.5% Senior Notes, we have also used the proceeds to repay a portion of the outstanding borrowings under our Revolving Credit Facility.

November 2013 Shelf Registration Statement.  In October 2013, we filed the 2013 SRS and in November 2013, the SEC declared it effective. The following transactions have been executed pursuant to the 2013 SRS:

The 2013 SRS expired in November 2016 when it was replaced with the 2016 SRS.

For additional information, see Notes 1, 9, 11 and 16 to the consolidated financial statements.

EX 99.2-22

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EXHIBIT 99.2

 

Debt

Revolving Credit Facility.  We have a $1.25 billion senior secured Revolving Credit Facility. As of December 31, 2016, the outstanding balance of the Revolving Credit Facility was $648.0 million and the unused portion totaled $602.0 million. There were no defaults or events of default during 2016 and, as of December 31, 2016, we were in compliance with the covenants in the Revolving Credit Facility.

Senior Notes.   In July 2014, the Co-Issuers co-issued the 5.5% Senior Notes, and in June 2013, they co-issued the 7.5% Senior Notes. There were no defaults or events of default during 2016 on either series of senior notes.

SMP Holdings Credit Facility.  SMP Holdings had a senior secured revolving credit facility and a senior secured term loan which were used to support the development of the assets acquired in the 2016 Drop Down.  As such, Summit Investments allocated this debt and the associated interest expense to us during the common control period but retained the debt subsequent to the closing of the 2016 Drop Down.

For additional information on our long-term debt and debt allocated to us, see Notes 9, 16 and 17 to the consolidated financial statements.

Deferred Purchase Price Obligation

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Critical Accounting Estimates below and Note 16 to the consolidated financial statements).

Cash Flows

Due to the common control aspect in a drop down transaction, we account for drop downs on an “as-if pooled” basis for the periods during which common control existed.  As such, cash flows retrospectively reflect the cash flows associated with (i) the assets acquired from Summit Investments and (ii) the assets and liabilities allocated to the Partnership from Summit Investments.

The components of the net change in cash and cash equivalents were as follows:

 

Operating activities. Cash flows from operating activities for the year ended December 31, 2016 increased primarily as a result of:

Cash flows from operating activities for the year ended December 31, 2015 increased primarily as a result of:

These items were partially offset by the 2015 impact of net cash paid for environmental remediation expenses.

Investing activities. Details of cash flows from investing activities follow.

Cash flows used in investing activities for the year ended December 31, 2016 primarily reflected:

EX 99.2-23

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EXHIBIT 99.2

 

Cash flows used in investing activities for the year ended December 31, 2015 primarily reflected:

Cash flows used in investing activities for the year ended December 31, 2014 primarily reflected:

Financing activities. Details of cash flows from financing activities follow.

Net cash provided by financing activities for the year ended December 31, 2016 primarily reflected:

Net cash provided by financing activities for the year ended December 31, 2015 primarily reflected:

Net cash provided by financing activities for the year ended December 31, 2014 primarily reflected:

EX 99.2-24

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EXHIBIT 99.2

 

Contractual Obligations

The table below summarizes our contractual obligations as of December 31, 2016.

 

 

(1)  For the purpose of calculating future interest on the Revolving Credit Facility, assumes no change in balance or rate from December 31, 2016. Includes a 0.50% commitment fee on the unused portion of the Revolving Credit Facility. See Note 9 to the consolidated financial statements.

(2)  See Note 16 to the consolidated financial statements.

(3)  Represents agreements to purchase goods or services that are enforceable and legally binding.

(4)  See Item 2. Properties and Note 15 to the consolidated financial statements.

In February 2017, we issued $500.0 million of 5.75% senior, unsecured notes due 2025.  We used the proceeds therefrom to purchase and redeem all of the $300.0 million 7.5% Senior Notes due 2021 and to pay down $172.0 million on our Revolving Credit Facility which is due 2018.

Capital Requirements

Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time.  Our ability to grow cash distributions depends, in part, on our ability to capitalize on organic growth opportunities and make acquisitions that increase the amount of cash generated from our operations on a per-unit basis, along with other factors.

Developing, owning and operating midstream energy infrastructure assets requires significant investment in the maintenance of existing gathering systems and the construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either:

For the year ended December 31, 2016, cash paid for capital expenditures totaled $142.7 million, compared with $272.2 million for the year ended December 31, 2015 and $343.4 million for the year ended December 31, 2014 (see Note 3 to the consolidated financial statements). Maintenance capital expenditures totaled $17.7 million for the year ended December 31, 2016, compared with $12.7 million for the year ended December 31, 2015 and $18.1 million for the year ended December 31, 2014.  For the year ended December 31, 2016, contributions to equity method investees totaled $31.6 million, compared with $86.2 million for the year ended December 31, 2015 and $145.1 million for the year ended December 31, 2014 (see Note 7 to the consolidated financial statements).  The

EX 99.2-25

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EXHIBIT 99.2

 

year-over-year declines in cash paid for capital expenditures primarily reflected the buildout in 2015 and 2014 of recently acquired systems and the completion of several large capital projects on legacy systems.

The acquisition component of our principal business strategy has required and will continue to require significant expenditures by us. 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 intend to continue to pursue accretive acquisitions of midstream assets from third parties. However, their size, timing and/or contribution to our operations and financial results cannot be reasonably estimated.  Furthermore, there are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreement with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other sources such as our Sponsor and Summit Investments, among other factors.

We rely primarily on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.  We believe that our Revolving Credit Facility, together with financial support from our Sponsor and/or access to the debt and equity capital markets, will be adequate to finance our growth objectives for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

Distributions, Including IDRs

Based on the terms of our Partnership Agreement, we expect to distribute most of the cash generated by our operations to our unitholders. With respect to our payment of IDRs to the General Partner, we reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013.  We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014.  For additional information, see "Our Cash Distribution Policy and Restrictions on Distributions" in Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities and Note 11 to the consolidated financial statements.

Credit and Counterparty Concentration Risks

We examine the creditworthiness of counterparties 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.

Given the current environment, certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain.  The majority of our infrastructure is connected directly to our customer’s wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customer’s commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting their MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due.  We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.

For additional information, see Notes 3, 8 and 10 to the consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the year ended December 31, 2016.

EX 99.2-26

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EXHIBIT 99.2

 

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the consolidated financial statements.

The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value and recognition of deferred revenue. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results. Our critical accounting estimates are as follows:

Recognition and Impairment of Long-Lived Assets

Our long-lived assets include property, plant and equipment, amortizing intangible assets and goodwill.

Property, Plant and Equipment and Amortizing Intangible Assets.  As of December 31, 2016, we had net property, plant and equipment with a carrying value of approximately $1.85 billion and net amortizing intangible assets with a carrying value of approximately $421.5 million.

When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable as well as in connection with any goodwill impairment evaluations.

With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using an income approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

For additional information, see Notes 2, 4 and 5 to the consolidated financial statements.

Goodwill.  We evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill.

2016 Impairment Evaluations. We performed our 2016 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

2015 Impairment Evaluations. During the latter part of the fourth quarter of 2015 and the early part of the first quarter of 2016, the declines in forward prices for natural gas, NGLs and crude oil accelerated significantly.  As a result, the energy sector's public debt and equity market experienced increased volatility, particularly for comparable companies operating in the midstream services sector.  Additionally, during this period, the values of our publicly traded equity and debt instruments decreased as did those of comparable midstream companies.  Due to (i) the increased market volatility, (ii) the decrease in market values of comparable companies, (iii) the continued trend of falling commodity prices and (iv) the finalization of our annual financial and operating plans which took into account changes resulting from expected levels of drilling activity, we concluded that a triggering event occurred which required that we test the goodwill associated with our Grand River and Polar and Divide reporting units for

EX 99.2-27

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EXHIBIT 99.2

 

impairment as of December 31, 2015.  In connection therewith, we concluded that the goodwill associated with our Grand River and Polar and Divide reporting units was fully impaired and we wrote off the associated balances.

2014 Impairment Evaluations.  During the latter part of the fourth quarter of 2014, the declines in prices for natural gas, NGLs and crude oil accelerated, negatively impacting producers in each of our areas of operation.  As a result, we considered whether any of our goodwill could have been impaired.  In connection with this assessment, we concluded that a fourth quarter triggering event had occurred which required that we test the goodwill associated with our Polar and Divide and Bison Midstream reporting units for impairment as of December 31, 2014.  In connection therewith, we concluded that (i) the goodwill associated with our Polar and Divide reporting unit was not impaired and (ii) the goodwill associated with our Bison Midstream reporting unit was fully impaired and we wrote off the associated balance.

See Notes 2 and 6 for additional information.

Deferred Purchase Price Obligation

We recognized the Deferred Purchase Price Obligation to reflect the present value of the Remaining Consideration. Our calculation of the Remaining Consideration incorporates:

We then discount the Remaining Consideration using a commensurate risk-adjusted discount rate and recognize the present value on our consolidated balance sheets with the change in present value recognized in earnings in the period of change.

The estimates and expectations used in calculating the prospective component of Remaining Consideration and the present value calculation of the Remaining Consideration involve a significant amount of judgment as the calculations are based on future events and/or conditions, including (i) revenues, (ii) estimates of future volume throughput, capital expenditures, operating costs and their timing and (iii) economic and regulatory climates, among other factors. Our estimates of these inputs are inherently imprecise because they reflect our expectation of future conditions that are largely outside of our control. While the assumptions used are consistent with our current business plans and investment decisions, these assumptions could change significantly during the period leading up to settlement of the Deferred Purchase Price Obligation. See Note 16 to the consolidated financial statements for additional information.

Minimum Volume Commitments

Certain of our gathering agreements provide for a monthly, quarterly or annual MVC from our customers.  As of December 31, 2016, we had MVCs totaling 1.1 Bcfe/d through 2021.

Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that period.

We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering fees in excess of its MVCs in subsequent periods.

We billed $64.6 million of MVC shortfall payments to customers that did not meet their MVCs during 2016. For those customers that do not have credit banking mechanisms in their gathering agreements, or have no ability to use MVC shortfall payments as credits, the MVC shortfall payments from these customers are accounted for as gathering revenue in the period that they are earned.  We recognized $13.3 million of gathering revenue due to the credit bank expiration of previous MVC shortfall payments.  MVC shortfall payment adjustments in 2016 totaled $0.3 million and included adjustments related to future anticipated shortfall payments from certain customers in the Williston Basin, Piceance/DJ Basins, Barnett Shale and Marcellus Shale segments.

EX 99.2-28

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EXHIBIT 99.2

 

The following table presents the impact of our MVC activity by reportable segment during the year ended December 31, 2016.

 

Deferred Revenue.  We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable gathering agreement.  We also recognize deferred revenue when it is determined that a given amount of MVC shortfall payments cannot be recovered by offsetting gathering or processing fees in subsequent contracted measurement periods. In making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.

We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less. We classify deferred revenue as noncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is more than 12 months.  As of December 31, 2016, noncurrent deferred revenue totaled $57.5 million and represents amounts that provide these customers the ability to offset their gathering fees, as determined by the MVC contract, to the extent that their throughput volumes exceed their MVC.

Adjustments for MVC Shortfall Payments.  We estimate the impact of expected MVC shortfall payments for inclusion in our calculation of segment adjusted EBITDA.  Adjustments related to MVC shortfall payments account for:

We estimate expected MVC shortfall payments based on assumptions including, but not limited to, contract terms, historical volume throughput data and expectations regarding future investment, drilling and production.

EX 99.2-29

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EXHIBIT 99.2

 

For additional information, see Notes 2, 3 and 8 to the consolidated financial statements and the "Results of Operations" and "Liquidity and Capital Resources—Credit and Counterparty Concentration Risks" sections herein.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, Summit Investments or our Sponsor, are also forward-looking statements.  These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team.  All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph.  These risks and uncertainties include, among others:

EX 99.2-30

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EXHIBIT 99.2

 

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units and senior notes.

The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

EX 99.2-31

EXHIBIT 99.3

Item 8. Financial Statements and Supplementary Data.

 

 

EX 99.3-1

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EXHIBIT 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of Summit Midstream GP, LLC and the unitholders of Summit Midstream Partners, LP

The Woodlands, Texas

We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LP and subsidiaries (the "Partnership") as of December 31, 2016 and 2015, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements as of and for the year ended December 31, 2016 of Ohio Condensate Company, L.L.C. and Ohio Gathering Company, L.L.C. (collectively “Ohio Gathering”), the Partnership's investments which are accounted for by use of the equity method. The accompanying 2016 consolidated financial statements of the Partnership include its equity investments in Ohio Gathering of $707,415,000 as of December 31, 2016, and its loss from equity method investees of $30,344,000 for the year then ended. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Ohio Gathering as of and for the year ended December 31, 2016, is based solely on the reports of the other auditors.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 and the reports of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Summit Midstream Partners, LP and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2017 expressed an unqualified opinion on the Partnership's internal control over financial reporting based on our audit (not presented herein).

 

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 27, 2017 (November 6, 2017 as to the effects of the segment change as described in Note 3)

 

 

 

EX 99.3-2

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EXHIBIT 99.3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements.

EX 99.3-3

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EXHIBIT 99.3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these consolidated financial statements.

 

EX 99.3-4

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EXHIBIT 99.3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

 

 

EX 99.3-5

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EXHIBIT 99.3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)

 

EX 99.3-6

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EXHIBIT 99.3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)

The accompanying notes are an integral part of these consolidated financial statements.

 

 

EX 99.3-7

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EXHIBIT 99.3

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

EX 99.3-8

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EXHIBIT 99.3

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

 

EX 99.3-9

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EXHIBIT 99.3

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

The accompanying notes are an integral part of these consolidated financial statements.

 

 

EX 99.3-10

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EXHIBIT 99.3

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization.  SMLP, a Delaware limited partnership, was formed in May 2012 and began operations in October 2012 in connection with its IPO of common limited partner units. SMLP is a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States.  Our business activities are conducted through various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company.  References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

The General Partner, a Delaware limited liability company, manages our operations and activities.  Summit Investments, a Delaware limited liability company, is the ultimate owner of our General Partner and has the right to appoint the entire Board of Directors of our General Partner. Summit Investments is controlled by Energy Capital Partners.

In addition to its approximate 2% general partner interest in SMLP (including the IDRs) in respect of SMLP, Summit Investments has indirect ownership interests in our common units.  As of December 31, 2016, Summit Investments beneficially owned 29,854,581 SMLP common units.

Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by Summit Investments, but these individuals are sometimes referred to as our employees.

Effective with the completion of its IPO, SMLP had a 100% ownership interest in Summit Holdings, which had a 100% ownership interest in both DFW Midstream and Grand River.

In February 2013, Summit Investments acquired all of the outstanding membership interests of Bear Tracker Energy, LLC and subsequently renamed it Meadowlark Midstream.  In June 2013, the Partnership acquired all of the membership interests of Bison Midstream from a subsidiary of Summit Investments (the "Bison Drop Down").  As such, the Bison Drop Down was determined to be a transaction among entities under common control.  The net assets that comprise Bison Midstream were carved out from Meadowlark Midstream in connection with the Bison Drop Down.  Common control of Bison Midstream began in February 2013.

In June 2013, Mountaineer Midstream, LLC, a newly formed, wholly owned subsidiary of the Partnership, acquired natural gas gathering pipeline and compression assets from an affiliate of MarkWest Energy Partners, L.P.  In December 2013, Mountaineer Midstream, LLC was merged into DFW Midstream.

In March 2014, the Partnership acquired all of the membership interests of Red Rock Gathering from a subsidiary of Summit Investments (the "Red Rock Drop Down").  As such, the Red Rock Drop Down was determined to be a transaction among entities under common control.  Common control of Red Rock Gathering began in October 2012.  Concurrent with the closing of the Red Rock Drop Down, SMLP contributed its interest in Red Rock Gathering to Grand River.

In May 2015, the Partnership acquired all of the membership interests of Polar Midstream and Epping from a subsidiary of Summit Investments (the "Polar and Divide Drop Down").  As such, the Polar and Divide Drop Down was determined to be a transaction among entities under common control.  Polar Midstream's net assets were carved out of Meadowlark Midstream immediately prior to the Polar and Divide Drop Down.  Concurrent with the closing of the Polar and Divide Drop Down, Epping became a wholly owned subsidiary of Polar Midstream and SMLP contributed Polar Midstream (including Epping) to Bison Midstream. Common control began in (i) February 2013 for Polar Midstream and (ii) April 2014 for Epping.

EX 99.3-11

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EXHIBIT 99.3

 

In February 2016, the Partnership and SMP Holdings, a wholly owned subsidiary of Summit Investments, entered into a contribution agreement (the "Contribution Agreement") pursuant to which SMP Holdings agreed to contribute to the Partnership substantially all of its limited partner interest in OpCo, a Delaware limited partnership that owns (i) 100% of the issued and outstanding membership interests of Summit Utica, Meadowlark Midstream and Tioga Midstream and collectively with Summit Utica and Meadowlark Midstream, the "Contributed Entities"), each a limited liability company and (ii) a 40% ownership interest in each of OGC and OCC (collectively with OpCo and the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down closed in March 2016; concurrent therewith, a subsidiary of Summit Investments retained a 1% noncontrolling interest in OpCo, which is managed by OpCo GP, a Delaware limited liability company and a wholly owned subsidiary of Summit Holdings.

Business Operations. We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based agreements with our customers.  Our results are driven primarily by the volumes of natural gas that we gather, treat, compress and process as well as by the volumes of crude oil and produced water that we gather.  We are the owner-operator of or have significant ownership interests in the following gathering systems:

Meadowlark Midstream is the legal entity which owns (i) certain crude oil and produced water gathering pipelines, which are managed and reported as part of the Polar and Divide system subsequent to the 2016 Drop Down and (ii) Niobrara G&P, which is managed and reported as part of the Grand River system subsequent to the 2016 Drop Down.

Presentation and Consolidation.  We prepare our consolidated financial statements in accordance with GAAP as established by the FASB.  We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenue and expense and the disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

EX 99.3-12

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EXHIBIT 99.3

 

The consolidated financial statements include the assets, liabilities and results of operations of SMLP and its wholly owned subsidiaries.  All intercompany transactions among the consolidated entities have been eliminated in consolidation.  For the purposes of the consolidated financial statements, SMLP's results of operations reflect the results of operations of: (i) Bison Midstream, Polar and Divide, Grand River, Niobrara G&P, DFW Midstream and Mountaineer Midstream for all periods presented, (ii) Ohio Gathering since January 2014, (iii) Tioga Midstream since April 2014 and (iv) Summit Utica since December 2014.  The financial position, results of operations and cash flows of Polar and Divide and Niobrara G&P included herein have been derived from the accounting records of Meadowlark Midstream on a carve-out basis (see Note 2).  The carve-out allocations and estimates were based on methodologies that management believes are reasonable.  The carve-out results reflected herein, however, may not reflect what these entities' financial position, results of operations or cash flows would have been if any had been a stand-alone company.

SMLP recognized its drop down acquisitions at Summit Investments' historical cost because the acquisitions were executed by entities under common control.  The excess of Summit Investments' net investment over the consideration paid and recognized for a contributed subsidiary is recognized as an addition to partners' capital, while the excess of purchase price paid and recognized over net investment is recognized as a reduction to partners' capital.  Due to the common control aspect, we account for drop down transactions on an “as-if pooled” basis for the periods during which common control existed.

Reclassifications. In the first quarter of 2016, we adopted ASU No. 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). As a result, these consolidated financial statements reflect the retrospective reclassification of $9.2 million of debt issuance costs from other noncurrent assets to long-term debt at December 31, 2015 (see Note 2).

 

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 our customers and other counterparties. We evaluate the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent we doubt the collectability of a specific customer or counterparty receivable, we recognize an allowance for doubtful accounts.  

Other Current Assets.  Other current assets primarily consist of the current portion of prepaid expenses that are charged to expense over the period of benefit or the life of the related contract.  

Property, Plant and Equipment. We record property, plant and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress.  To the extent that Summit Investments incurred interest expense related to capital projects of assets that have been acquired by the Partnership, the associated interest expense is allocated to the drop down assets as a noncash equity contribution and capitalized into the basis of the asset.

We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow.

EX 99.3-13

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EXHIBIT 99.3

 

Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated.  

We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any.

Accrued capital expenditures are reflected in trade accounts payable.  

Asset Retirement Obligations. We record a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, we then evaluate whether the expected date and related costs of retirement can be estimated.  We have concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because we did not have sufficient information to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of any significant assets, we did not provide for any asset retirement obligations as of December 31, 2016 or 2015.  

Amortizing Intangibles. Upon the acquisition of DFW Midstream, certain of its gas gathering contracts were deemed to have above-market pricing structures while another was deemed to have pricing that was below market. We have recognized the above-market contracts as favorable gas gathering contracts. We have recognized the below-market contract as the unfavorable gas gathering contract and included it in other noncurrent liabilities. We amortize these contracts using a straight-line method over the contract's estimated useful life.  We define useful life as the period over which the contract is expected to contribute to our future cash flows. These contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these contracts in other revenues.

We amortize all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 10 years to 25 years. We recognize the amortization expense associated with these contracts in depreciation and amortization expense.

We have rights-of-way associated with city easements and easements granted within existing rights-of-way. We amortize these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years. We recognize the amortization expense associated with rights-of-way assets in depreciation and amortization expense.

Goodwill. Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

We test goodwill for impairment using a two-step quantitative test. In the first step, we compare the fair value of the reporting unit to its carrying value, including goodwill. To estimate the fair value of the reporting units under step one, we utilize two valuation methodologies: the market approach and the income approach. Both of these approaches incorporate significant estimates and assumptions to calculate enterprise fair value for a reporting unit. The most significant estimates and assumptions inherent within these two valuation methodologies are: (i) determination of the weighted-average cost of capital; (ii) the selection of guideline public companies; (iii) market multiples; (iv) weighting of the income and market approaches; (v) growth rates; (vi) commodity prices; and (vi) the expected levels of throughput volume gathered. Changes in these and other assumptions could materially affect the estimated amount of fair value for any of our reporting units.  

If the reporting unit’s fair value exceeds its carrying amount, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed.  

EX 99.3-14

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EXHIBIT 99.3

 

If we determine that the reporting unit’s carrying value exceeds its fair value, we proceed to step two. In step two, we compare the carrying value of the reporting unit to its implied fair value. Significant estimates and assumptions utilized in the determination of a reporting unit's implied fair value are based on a variety of factors specific to a given reporting unit's individual assets and liabilities as well as market and industry considerations.  If we determine that the carrying amount of a reporting unit's goodwill exceeds its implied fair value, we recognize the excess of the carrying value over the implied fair value as an impairment loss.

Equity Method Investments. We account for investments in which we exercise significant influence using the equity method so long as we (i) do not control the investee and (ii) are not the primary beneficiary.  We recognize these investments in investment in equity method investees in the accompanying consolidated balance sheets. We recognize our proportionate share of earnings or loss in net income on a one-month lag.

We recognize an other-than-temporary impairment for losses in the value of equity method investees when evidence indicates that the carrying amount is no longer supportable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. We evaluate our equity method investments whenever evidence exists that would indicate a need to assess the investment for potential impairment.  

Other Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the closing of our Revolving Credit Facility and related amendments. We capitalize and then amortize these debt issuance costs on a straight-line basis over the life of the respective debt instrument.  We recognize amortization of Revolving Credit Facility debt issuance costs in interest expense.

Debt Issuance Costs.  Debt issuance costs, other than those associated with our Revolving Credit Facility, are reflected in the carrying value of the Senior Notes as an adjustment to the principal amount and amortized on a straight-line basis over the life of the respective debt instrument.  We recognize Senior Notes debt issuance costs in interest expense.

Deferred Purchase Price Obligation. We recognize a liability for the Deferred Purchase Price Obligation (as defined later) to reflect the expected value of the Remaining Consideration to be paid in 2020 for the acquisition of the 2016 Drop Down Assets. We estimate Remaining Consideration by summing the calculations of (i) actual capital expenditures incurred and Business Adjusted EBITDA (as defined later) recognized from the 2016 Drop Down Assets during the period since closing the 2016 Drop Down to the current balance sheet date and (ii) estimates of projected capital expenditures and Business Adjusted EBITDA related to the 2016 Drop Down Assets for periods subsequent to the respective balance sheet date until December 31, 2019. We discount the Remaining Consideration using a commensurate risk-adjusted discount rate and recognize the change in present value of the Remaining Consideration in earnings in the period of change. Our recognition of the change in present value of the Remaining Consideration in the consolidated statements of operations represents the change in present value, which comprises a time value of money concept, as well as (i) actual results from the 2016 Drop Down Assets and (ii) adjustments to projections and the expected value of the Remaining Consideration (see Note 16).

Impairment of Long-Lived Assets. We test assets 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 (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If we conclude that an asset's carrying value will not be recovered through future cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. We determine fair value using either a market-based approach or an income-based approach.  We discuss our policy for goodwill impairment above.

Derivative Contracts.  We have commodity price exposure related to our sale of the physical natural gas we retain from certain DFW Midstream system customers and our procurement of electricity to operate the DFW Midstream system's electric-drive compression assets.  Our gas gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we gather to offset the power costs we incur to operate

EX 99.3-15

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EXHIBIT 99.3

 

these electric-drive compression assets. We manage this 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 based on the Waha Hub Index. Because we sell our retainage gas from these customers at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between a portion of our compression electricity expense and natural gas retainage sales.  

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values.  We have designated these contracts as normal under the normal purchase and sale exception under the accounting standards for derivatives. We do not enter into risk management contracts for speculative purposes.

Fair Value of Financial Instruments.  The fair-value-measurement standard under GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which the inputs are observable. The three levels of the fair value hierarchy are as follows:  

Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that 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.  We recognize gain contingencies when their realization is assured beyond a reasonable doubt.

Noncontrolling Interest. Noncontrolling interest represents the ownership interests of third-party entities in the net assets of our consolidated subsidiaries. For financial reporting purposes, we consolidate OpCo and its wholly owned subsidiaries with our wholly owned subsidiaries and the 1% ownership interest in OpCo is reflected as noncontrolling interest in partners' capital. We reflect changes in our ownership of OpCo as adjustments to noncontrolling interest.

Revenue Recognition. We generate the majority of our revenue from the gathering, treating and processing services that we provide to our customers. We also generate revenue from our marketing of natural gas, NGLs and condensate. We realize revenues by receiving fees from our customers or by selling the residue natural gas, NGLs and condensate.  

We recognize revenue earned from fee-based gathering, treating and processing services in gathering services and related fees revenue. We also earn revenue from the sale of physical natural gas purchased from our customers under percentage-of-proceeds arrangements. These revenues are recognized in natural gas, NGLs and condensate sales with corresponding expense recognition for the producer's share of the proceeds in cost of natural gas and NGLs. We sell substantially all of the natural gas that we retain from certain DFW Midstream customers to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from our gathering services at Grand River. Revenues from the retainage of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in

EX 99.3-16

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EXHIBIT 99.3

 

operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in other revenues.  

We recognize revenue 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.  

We provide gathering and/or processing services principally under contracts that contain one or more of the following arrangements:  

Certain of our gathering and processing agreements provide for a monthly, quarterly or annual MVC. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.  

We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods.  

We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volume throughput, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable gathering or processing agreement.  We also recognize deferred revenue in revenues when it is determined that a given amount of MVC shortfall payments cannot be recovered by offsetting gathering or processing fees in subsequent contracted measurement periods. In making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.

We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less. We classify deferred revenue as noncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is more than 12 months.  

Unit-Based Compensation.  For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense in the statements of operations over the vesting period of the respective awards.

EX 99.3-17

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EXHIBIT 99.3

 

Income Taxes.  As a partnership, we are generally not subject to federal and state income taxes, except as noted below. However, our unitholders are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements under our Partnership Agreement.

In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses.  Our financial statements reflect provisions for these tax obligations.    

Earnings or Loss Per Unit. We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our Partnership Agreement, to limited partners under the two-class method, after deducting (i)  the 1% noncontrolling interest in OpCo (for periods subsequent to the 2016 Drop Down), (ii) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (iii) the General Partner's approximate 2% interest in net income or loss and (iv) any payment of IDRs, by the weighted-average number of limited partner units outstanding. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.

Comprehensive Income or Loss.  Comprehensive income or loss is the same as net income or loss for all periods presented.

Environmental Matters.  We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their realization is assured beyond a reasonable doubt.  

Carve-Out Entities, Assets, Liabilities and Expenses. For drop down transactions involving entities that were carved out of other entities, the majority of the assets and liabilities allocated to the carve-out entity are specifically identified based on the original entity's existing divisional organization. Goodwill is allocated to the carve-out entity based on initial purchase accounting estimates. Revenues and depreciation and amortization are specifically identified based on the relationship of the carve-out entity to the original entity's existing divisional structure. Operation and maintenance and general and administrative expenses are allocated to the carve-out entity based on volume throughput.

For drop down transactions involving assets, liabilities and expenses that were carved out of other entities, the majority of the assets and liabilities allocated to the carve-out are specifically identified based on the original entity's existing divisional organization. Depreciation and amortization are specifically identified based on the relationship of the carve-out entity to the original entity's existing divisional structure. General and administrative expenses are allocated to the carve-out entity based on an allocation of Summit Investments' consolidated expenses.

EX 99.3-18

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EXHIBIT 99.3

 

Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with debt incurred by Summit Investments or a subsidiary thereof, which was allocated to but not ultimately assumed by the Partnership and later replaced with bank borrowings or debt capital at the Partnership, we allocate a portion of that debt, net of debt issuance costs, to the drop down assets during the common control period. Interest expense is allocated and recognized during the common control period. Any outstanding debt balance or principal is included in the calculation of the excess or deficit of acquired carrying value relative to consideration paid and recognized.

Recent Accounting Pronouncements.  Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements.  Accounting standards that have or could possibly have a material effect on our financial statements are discussed below.

Recently Adopted Accounting Pronouncements.  We have recently adopted the following accounting pronouncements:

Accounting Pronouncements Pending Adoption. We are currently in the process of evaluating the applicability and/or impact of the following accounting pronouncements:

EX 99.3-19

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EXHIBIT 99.3

 

 

 

3. SEGMENT INFORMATION

We evaluate our business operations each reporting period to determine whether any of our gathering system operating segments in which we internally report financial information are considered significant and would require us to separately disclose certain segment financial information in our external reporting. As a result of our

EX 99.3-20

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EXHIBIT 99.3

 

evaluation for the quarterly period ended June 30, 2017, we determined that both the Summit Utica natural gas gathering system and the Ohio Gathering natural gas gathering system, each previously reported within the Utica Shale reportable segment, were and are expected to continue to be significant operating segments. As such, we modified our current segments such that the Utica Shale reportable segment includes the Summit Utica gathering system and the Ohio Gathering reportable segment includes our ownership interest in OGC and OCC. We have disclosed the required segment information for Summit Utica and Ohio Gathering and the periods presented herein have been recast to reflect this change.

As of December 31, 2016, our reportable segments are:

Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations.

As noted above, the Ohio Gathering reportable segment includes our investment in Ohio Gathering (see Note 7). Income or loss from equity method investees, as reflected on the statements of operations, solely relates to Ohio Gathering and is recognized and disclosed on a one-month lag (see Note 7). No other line items in the statements of operations or cash flows, as disclosed in the tables below, include results for our investment in Ohio Gathering.

Corporate and other represents those results that are (i) not specifically attributable to a reportable segment (ii) not individually reportable or (iii) that have not been allocated to our reportable segments, including certain general and administrative expense items and transaction costs, for the purpose of evaluating their performance.

Assets by reportable segment follow.

 

 

For information on the sale or impairment of long-lived assets, other than goodwill, see Note 4.  For information on goodwill by reportable segment, including goodwill impairments, see Note 6.

EX 99.3-21

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EXHIBIT 99.3

 

Revenues by reportable segment follow.

 

(1) Excludes revenues earned by Ohio Gathering due to equity method accounting.

Counterparties accounting for more than 10% of total revenues were as follows:

 

* Less than 10%

(1) Total revenues include recognition of revenue during the year ended December 31, 2015 that was previously deferred in connection with certain MVCs (see Note 8).

(2) Excludes revenues earned by Ohio Gathering due to equity method accounting.

Depreciation and amortization by reportable segment follows.

 

(1) Excludes depreciation and amortization recognized by Ohio Gathering due to equity method accounting.

(2) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues.

EX 99.3-22

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EXHIBIT 99.3

 

Cash paid for capital expenditures by reportable segment follow.

 

(1) Excludes cash paid for capital expenditures by Ohio Gathering due to equity method accounting.

We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) unit-based and noncash compensation, (vi) Deferred Purchase Price Obligation expense; (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains.  We define proportional adjusted EBITDA for our equity method investees as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items and (ii) amortization for deferred contract costs; multiplied by our ownership interest in Ohio Gathering during the respective period.

For the purpose of evaluating segment performance, we exclude the effect of corporate and other revenues and expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, interest expense, Deferred Purchase Price Obligation income or expense and income tax expense or benefit from segment adjusted EBITDA.  In the first quarter of 2015, we discontinued allocating certain corporate expenses, primarily salaries, benefits, incentive compensation and rent expense, to our then-reportable segments.  This change in allocation methodology was not implemented by Summit Investments with respect to Polar and Divide or the 2016 Drop Down Assets.  As a result of accounting for their activity on an as-if pooled basis due to common control, general and administrative expense allocations were higher for Polar and Divide and the 2016 Drop Down Assets during their respective common control periods.

EX 99.3-23

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EXHIBIT 99.3

 

Segment adjusted EBITDA by reportable segment follows.

A reconciliation of loss before income taxes and loss from equity method investees to total of reportable segments' measures of profit or loss follows.

We include adjustments related to MVC shortfall payments in our calculation of segment adjusted EBITDA to account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments.  With respect to the impact of a net change in deferred revenue for MVC shortfall payments, we treat increases in deferred revenue balances as a favorable adjustment to segment adjusted EBITDA, while decreases in deferred revenue balances are treated as an unfavorable adjustment to segment adjusted EBITDA.  We also include a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment.  The expected MVC shortfall payment adjustments have not been billed to our customers and are not recognized in our consolidated financial statements.

EX 99.3-24

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EXHIBIT 99.3

 

Adjustments related to MVC shortfall payments by reportable segment follow.

 

 

   

 

 

4. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

During 2016, 2015 and 2014, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired.  As such, we reviewed the assets that had been identified as potentially impaired and estimated the fair value of the identified property, plant and equipment using a market-based approach.  For the assets which had fair values below their carrying value, we recognized the following long-lived asset impairments, by segment.

EX 99.3-25

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EXHIBIT 99.3

 

Our impairment determinations, in the context of these reviews, involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.  

During the fourth quarters of 2015 and 2014, we identified a need to evaluate the goodwill associated with certain of our gathering systems (see Note 6). In connection with these evaluations, we also evaluated the related property, plant and equipment associated therewith for impairment and concluded that no impairment was necessary.

Depreciation expense and capitalized interest follow.

  

 

 

5. AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT

Details regarding our intangible assets and the unfavorable gas gathering contract (included in other noncurrent liabilities), all of which are subject to amortization, follow.  

 

During the fourth quarters of 2015 and 2014, we identified a need to evaluate the goodwill associated with certain of our gathering systems (see Note 6). In connection with these evaluations, we also evaluated the related intangible assets associated therewith for impairment and concluded that no impairment was necessary.

EX 99.3-26

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EXHIBIT 99.3

 

We recognized amortization expense in other revenues as follows:

We recognized amortization expense in costs and expenses as follows:

The estimated aggregate annual amortization expected to be recognized as of December 31, 2016 for each of the five succeeding fiscal years follows.

 

 

 

6. GOODWILL

Current and historical goodwill is related to the original acquisitions of the Grand River, Bison Midstream, Polar and Divide and Mountaineer Midstream systems. The assets acquired in the Polar and Divide Drop Down were carved out of Meadowlark Midstream.  As such, we elected to apply the historical cost approach to determine the amount of goodwill to assign to the Polar and Divide reporting unit.  Our procedures indicated that the remaining goodwill balance at Meadowlark Midstream immediately prior to the Polar and Divide Drop Down was entirely attributable to the Polar and Divide reporting unit.

A rollforward of goodwill by reportable segment and in total follows.

EX 99.3-27

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EXHIBIT 99.3

 

Accumulated goodwill impairments by reportable segment for those reporting units that have previously recognized goodwill follow.

As discussed in Note 2, we evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill.

We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2016 using a combination of the income and market approaches. We determined that its fair value substantially exceeded its carrying value, including goodwill; as such, there were no impairments of goodwill during 2016.

2014 Annual Impairment Evaluation.  In September 2014, we performed our annual goodwill impairment testing as of September 30 using a combination of the income and market approaches. We determined that the fair value of the Grand River, Mountaineer Midstream and Polar and Divide reporting units substantially exceeded their carrying value, including goodwill.  We also determined that the fair value of the Bison Midstream reporting unit exceeded its carrying value. However, it did not exceed its carrying value, including goodwill, by a substantial amount.  Because the fair value of each reporting unit exceeded its carrying value, including goodwill, there were no associated impairments of goodwill in connection with our 2014 annual goodwill impairment test.

Fourth Quarter 2014 Goodwill Impairment. During the latter part of the fourth quarter of 2014, the declines in prices for natural gas, NGLs and crude oil accelerated, negatively impacting producers in each of our areas of operation.  As a result, we considered whether the goodwill associated with our Grand River, Mountaineer Midstream, Polar and Divide and Bison Midstream reporting units could have been impaired.  Our assessments related to Grand River and Mountaineer Midstream did not result in an indication that the associated goodwill had been impaired.

Our assessment related to the Polar and Divide and Bison Midstream reporting units did result in an indication that the associated goodwill could have been impaired.  We noted that both reporting units were impacted by the recent price declines. We also noted that a key Bison Midstream customer announced that it was delaying its previously announced drilling plans which caused SMLP to reduce its forecasted volume assumption. The impact of these events increased the likelihood that the goodwill associated with the Polar and Divide and Bison Midstream reporting units could have been impaired.  As such, we concluded that a triggering event occurred during the fourth quarter of 2014 requiring that we test the goodwill associated with these reporting units for impairment.

In connection therewith, we reperformed our step one analyses for each as of December 31, 2014. To estimate the fair value of the reporting units, we utilized two valuation methodologies: the market approach and the income approach.

The results of our step one goodwill impairment testing indicated that the fair value of the Polar and Divide reporting unit exceeded its carrying value, including goodwill as of December 31, 2014. As a result, there was no associated impairment of goodwill in connection with the fourth quarter 2014 triggering event.

The results of our step one goodwill impairment testing indicated that the fair value of the Bison Midstream reporting unit was below its carrying value, including goodwill as of December 31, 2014.  As a result, we performed step two of the goodwill impairment test.

EX 99.3-28

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EXHIBIT 99.3

 

To perform step two, we first determined the fair values of the identifiable assets and liabilities.  Significant assumptions utilized in the determination of the fair value of each reporting unit's individual assets and liabilities included the determination of discount rate and contributory asset charge utilized in our calculation of the fair value of our contract intangibles, expected levels of throughput volume and associated capital expenditures and commodity prices.

In the first quarter of 2015, we finalized our calculations of the fair values of the identified assets and liabilities in step two of the December 31, 2014 goodwill impairment testing for the Bison Midstream reporting unit. This process confirmed the preliminary goodwill impairment of $54.2 million that was recognized as of December 31, 2014.

2015 Annual Impairment Evaluation.  We performed our annual goodwill impairment testing as of September 30, 2015 using a combination of the income and market approaches. We determined that the fair value of the Grand River, Mountaineer Midstream and Polar and Divide reporting units exceeded their carrying value, including goodwill.  Because the fair value of each reporting unit exceeded its carrying value, including goodwill, there were no associated impairments of goodwill in connection with our 2015 annual goodwill impairment test.

Fourth Quarter 2015 Goodwill Impairments.  During the latter part of the fourth quarter of 2015 and the early part of the first quarter of 2016, the declines in forward prices for natural gas, NGLs and crude oil accelerated significantly.  As a result, the energy sector's public debt and equity market experienced increased volatility, particularly for comparable companies operating in the midstream services sector.  Additionally, during this period, the values of our publicly traded equity and debt instruments decreased as did those of comparable midstream companies.  

Due to (i) the increased market volatility, (ii) the decrease in market values of comparable companies, (iii) the continued trend of falling commodity prices and (iv) the finalization of our annual financial and operating plans which took into account changes resulting from expected levels of drilling activity, we concluded that a triggering event occurred during the fourth quarter of 2015 requiring that we test the goodwill associated with our Grand River and Polar and Divide reporting units.  Our assessment related to Mountaineer Midstream did not result in an indication that a triggering event had occurred for Mountaineer Midstream.  

In connection therewith, we updated our step one analyses as of December 31, 2015. These updated analyses indicated that the carrying values for Grand River and Polar and Divide exceeded their estimated fair values.  As a result, we then performed step two of the goodwill impairment test for both reporting units.

To perform step two, we first determined the estimated fair values of the identifiable assets and liabilities.  Significant assumptions utilized in the determination of the fair value of each reporting unit's individual assets and liabilities included the determination of discount rate taking into consideration company-specific risks and contributory asset charge utilized in our contract intangibles, expected levels of throughput volume and associated capital expenditures.

In the first quarter of 2016, we finalized our calculations of the fair values of the identified assets and liabilities in step two of the December 31, 2015 goodwill impairment testing for the Grand River and Polar and Divide reporting units.  This process confirmed the preliminary goodwill impairments of $45.5 million for Grand River and $203.4 million for Polar and Divide that were recognized as of December 31, 2015.  

Fair Value Measurement.  Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

 

 

EX 99.3-29

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EXHIBIT 99.3

 

7. EQUITY METHOD INVESTMENTS

Ohio Gathering owns, operates and is currently developing midstream infrastructure consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate stabilization facility in the Utica Shale Play in southeastern Ohio. Ohio Gathering provides gathering services pursuant to primarily long-term, fee-based gathering agreements, which include acreage dedications.

In January 2014, Summit Investments acquired a 1% ownership interest in Ohio Gathering from Blackhawk Midstream, LLC ("Blackhawk") for $190.0 million. Concurrent with this acquisition, Summit Investments made an $8.4 million capital contribution to Ohio Gathering to maintain its 1% ownership interest.

The ownership interest Summit Investments acquired from Blackhawk included an option to increase the holder's ownership interest in Ohio Gathering to 40% (the "Option").  In May 2014, Summit Investments exercised the Option to increase its ownership to 40% (the "Option Exercise") and made the following payments (i) $326.6 million of capital contribution true-ups, (ii) $50.4 million of additional capital contributions to maintain its 40% ownership interest and (iii) $5.4 million of management fee payments that were recognized as capital contributions in its Ohio Gathering capital accounts. Concurrent with and subsequent to the Option Exercise, the non-affiliated owners have retained their respective 60% ownership interest in Ohio Gathering (the "Non-affiliated Owners").

Summit Investments accounted for its initial ownership interests in Ohio Gathering under the cost method due to its ownership percentage and because it determined that it was not the primary beneficiary.  Subsequent to the Option Exercise, Summit Investments accounted for its ownership interests in Ohio Gathering as equity method investments because it had joint control with the Non-affiliated Owners, which gave it significant influence.  This shift from the cost method to the equity method required that Summit Investments retrospectively reflect its investment in Ohio Gathering and the associated results of operations as if it had been utilizing the equity method since the inception of its investment.

Summit Investments recognized the $190.0 million that it paid to Blackhawk as an investment in Ohio Gathering at inception. In addition, Ohio Gathering had assigned a value of $7.5 million to the Option, recognized it initially as an asset and concurrently attributed the value of the Option to Blackhawk's capital account.  Upon acquiring Blackhawk's interest, the Option was reclassified from Blackhawk's capital account to Summit Investments' capital account in Ohio Gathering's records.  Neither of these transactions involved a flow of funds to or from Ohio Gathering.  As such, they created a basis difference between its recorded investment in equity method investees and that recognized and attributed to Summit Investments by Ohio Gathering.  In accordance with the retrospective recognition triggered by the Option Exercise, in February 2014, Summit Investments began amortizing these basis differences over the weighted-average remaining life of the contracts underlying Ohio Gathering's operations. The impact of amortizing these two basis differences resulted in a net decrease to Summit Investments' investment in equity method investees.

Subsequent to the Option Exercise, Summit Investments continued to make capital contributions to Ohio Gathering along with receiving distributions such that it maintained its 40% ownership interest through the 2016 Drop Down.  Subsequent to the 2016 Drop Down, SMLP began making contributions and receiving distributions and will also continue amortizing the two basis differences, as noted above.

In June 2016, an impairment loss was recognized by OCC. We recorded our 40% share of the impairment loss, or $37.8 million, in loss from equity method investees in the consolidated statements of operations.

A reconciliation of our 40% ownership interest in Ohio Gathering to our investment per Ohio Gathering's books and records follows.

EX 99.3-30

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EXHIBIT 99.3

 

 

Summarized balance sheet information for OGC and OCC follows (amounts represent 100% of investee financial information).

Summarized statements of operations information for OGC and OCC follows (amounts represent 100% of investee financial information).

 

 

 

8. DEFERRED REVENUE

The majority of our gas gathering agreements provide for a monthly, quarterly or annual MVC from our customers. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering or processing fee.

Many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our MVCs to the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period. These provisions include the following:  

EX 99.3-31

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EXHIBIT 99.3

 

A rollforward of current deferred revenue follows.

A rollforward of noncurrent deferred revenue follows.

In September 2015, we determined that it would be remote for a certain Piceance/DJ Basins customer to ship volumes in excess of its MVC such that it could recover certain previous MVC shortfall payments, which had been recorded as deferred revenue, as an offset to future gathering fees.  We based this determination on public statements by the customer regarding future drilling and investment plans in the area covered by the MVC contract.  Due to the remote nature of having to perform any services associated with the previously deferred gathering revenue, we evaluated (i) the terms of the customer contract, (ii) the capacity of the central receipt points for throughput volumes covered by the MVC contract and (iii) the size of the AMI, including the number of drilling locations to determine what amount of previously deferred gathering revenue had met the criteria for revenue recognition.  Our evaluation resulted in the recognition of $34.4 million of gathering services and related fees revenue that had been previously deferred with a corresponding reduction to deferred revenue.  This represents recognition of amounts deferred up to the September 2015 event triggering the conclusion that the associated shortfall payments should be recognized as revenue.  

As of December 31, 2016, accounts receivable included $46.0 million of total shortfall payment billings, of which $8.5 million related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods.

 

 

EX 99.3-32

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EXHIBIT 99.3

 

9. DEBT

Debt consisted of the following:

 

(1)  Issuance costs are being amortized over the life of the notes.

(2)  Debt was allocated to the 2016 Drop Down Assets prior to the closing of the 2016 Drop Down but was retained by Summit Investments after close.

The aggregate amount of debt maturing during each of the years after December 31, 2016 are as follow (in thousands):

Revolving Credit Facility.  Summit Holdings has a senior secured Revolving Credit Facility which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in November 2018, and includes a $200.0 million accordion feature.  

In February 2016, we closed on an amendment to the Revolving Credit Facility, which became effective concurrent with the March 2016 closing of the 2016 Drop Down. In connection with this amendment, (i) the Revolving Credit Facility's borrowing capacity increased from $700.0 million to $1.25 billion, (ii) a new investment basket allowing the Co-Issuers (as defined below) to buy back up to $100.0 million of our outstanding senior unsecured notes was included, (iii) the total leverage ratio was increased to 5.5 to 1.0 through December 31, 2016 and (iv) various amendments were approved to facilitate the 2016 Drop Down.  There was no change to the pricing or the maturity date of the Revolving Credit Facility in connection with this amendment.

Borrowings under the Revolving Credit Facility bear interest at LIBOR or an Alternate Base Rate ("ABR") plus an applicable margin ranging from 0.75% to 1.75% for ABR borrowings and 1.75% to 2.75% for LIBOR borrowings, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At December 31, 2016, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 3.27% and the unused portion of the Revolving Credit Facility totaled $602.0 million (subject to a commitment fee of 0.50%).

The Revolving Credit Facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the

EX 99.3-33

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EXHIBIT 99.3

 

Revolving Credit Facility. Prior to the 2016 Drop Down, the Revolving Credit Facility and Summit Holdings' obligations, were guaranteed by SMLP, Bison Midstream and its subsidiaries, Grand River and its subsidiary and DFW Midstream (the "Guarantor Subsidiaries" prior to the 2016 Drop Down).

Following the 2016 Drop Down, OpCo GP, OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream were added as subsidiary guarantors of the Revolving Credit Facility and the Senior Notes (as defined below).  On August 5, 2016, a consent and waiver agreement to the Revolving Credit Facility was executed effective March 30, 2016 (the "Consent and Waiver Agreement"), which removed the guarantees of OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream (collectively, the "Non-Guarantor Subsidiaries") from the Revolving Credit Facility and concurrently, from the Senior Notes.

The Revolving Credit Facility contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability to: (i) incur additional debt; (ii) make investments; (iii) engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) enter into swap agreements and power purchase agreements; (v) enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period; and (vi) prohibits the payment of distributions by Summit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings can make. In addition, the Revolving Credit Facility requires Summit Holdings to maintain a ratio of consolidated trailing 12-month earnings before interest, income taxes, depreciation and amortization ("EBITDA," as defined in the credit agreement) to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total net 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 270 days following certain acquisitions.  Additionally, the total leverage ratio upper limit can be increased from 5.0 to 1.0 to 5.5 to 1.0 at our option, subject to the inclusion of a senior secured leverage ratio (senior secured net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) upper limit of 3.75 to 1.0.

As of December 31, 2016, we were in compliance with the Revolving Credit Facility's covenants. There were no defaults or events of default during the year ended December 31, 2016.

Senior Notes.  In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp., together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "5.5% Senior Notes").  In June 2013, the Co-Issuers co-issued $300.0 million of 7.5% senior unsecured notes maturing July 1, 2021 (the "7.5% Senior Notes" and together with the 5.5% Senior Notes, the "Senior Notes").

Following execution of the Consent and Waiver Agreement, Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream and OpCo GP (collectively, the "Guarantor Subsidiaries" subsequent to the 2016 Drop Down after giving effect to the Consent and Waiver Agreement) and SMLP have fully and unconditionally and jointly and severally guaranteed the 5.5% Senior Notes and the 7.5% Senior Notes (collectively, the "Senior Notes") (see Note 17).  Prior to execution of the Consent and Waiver Agreement, the Senior Notes were guaranteed by SMLP and its then-subsidiaries other than the Co-Issuers.  At no time have the Senior Notes been guaranteed by the Co-Issuers.  There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan.  Finance Corp. has had no assets or operations since inception in 2013.

Subsequent Events. In February 2017, we amended the 2014 SRS to include additional guarantor subsidiaries and completed a public offering of $500.0 million principal 5.75% senior unsecured notes maturing April 15, 2025.  Concurrent therewith, we made a tender offer to purchase all of the outstanding 7.5% Senior Notes.  The tender offer expired on February 14, 2017 with $276.9 million validly tendered.  On February 16, 2017, we issued a notice of redemption for the 7.5% Senior Notes that remained outstanding subsequent to the tender offer.  The remaining $23.1 million of 7.5% Senior Notes will be redeemed on March 18, 2017, with payment made on March 20, 2017.  In addition to using the proceeds to purchase all of the outstanding 7.5% Senior Notes, we have also used the proceeds to repay a portion of the outstanding borrowings under our Revolving Credit Facility.  Remaining unamortized debt issuance costs on the 7.5% Senior Notes will be written off in the first quarter of 2017.

5.5% Senior Notes. We pay interest on the 5.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year. The 5.5% Senior Notes are senior, unsecured obligations and rank equally in right of

EX 99.3-34

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EXHIBIT 99.3

 

payment with all of our existing and future senior obligations. The 5.5% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness.  We used the proceeds from the issuance of the 5.5% Senior Notes to repay a portion of the balance outstanding under our Revolving Credit Facility.

At any time prior to August 15, 2017, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 5.5% Senior Notes at a redemption price of 105.500% of the principal amount of the 5.5% Senior Notes, plus accrued and unpaid interest, if any, to the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings.  On and after August 15, 2017, the Co-Issuers may redeem all or part of the 5.5% Senior Notes at a redemption price of 104.125% (with the redemption premium declining ratably each year to 100.000% on and after August 15, 2020), plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the senior notes.

The 5.5% Senior Notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate.

The 5.5% Senior Notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.5% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.5% Senior Notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $20.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture.  In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.5% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.5% Senior Notes may declare all the 5.5% Senior Notes to be due and payable immediately.

As of December 31, 2016, we were in compliance with the covenants of the 5.5% Senior Notes and there were no defaults or events of default during the year ended December 31, 2016.

7.5% Senior Notes. The 7.5% Senior Notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act.  Effective as of April 7, 2014, all of the holders of our 7.5% Senior Notes exchanged their unregistered senior notes and the guarantees of those notes for registered notes and guarantees. The terms of the registered senior notes were substantially identical to the terms of the unregistered senior notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the unregistered senior notes did not apply to the registered senior notes.

We paid interest on the 7.5% Senior Notes semi-annually in cash in arrears on January 1 and July 1 of each year.  Debt issuance costs of $7.4 million were being amortized to interest expense over the life of the senior notes.  The

EX 99.3-35

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EXHIBIT 99.3

 

7.5% Senior Notes were senior, unsecured obligations and ranked equally in right of payment with all of our then-existing senior obligations. The 7.5% Senior Notes were effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 7.5% Senior Notes to repay a portion of the balance outstanding under our Revolving Credit Facility.

Subsequent to June 2016, in accordance with the terms of the indenture, the Co-Issuers could redeem all or part of the 7.5% Senior Notes at a redemption price of 105.625% (with the redemption premium declining ratably each year to 100.000% on and after July 1, 2019), plus accrued and unpaid interest, if any.

The 7.5% Senior Notes indenture restricted SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants were subject to a number of important exceptions and qualifications.

As of December 31, 2016, we were in compliance with the covenants for the 7.5% Senior Notes and there were no defaults or events of default during the year ended December 31, 2016.

SMP Holdings Credit Facility.  SMP Holdings had a $250.0 million revolving credit facility (the "SMP Revolving Credit Facility") and a $200.0 million term loan (the "Term Loan" and, collectively with the SMP Revolving Credit Facility, the "SMP Holdings Credit Facility").  Because funding from the SMP Holdings Credit Facility was used to support the development of the 2016 Drop Down Assets, Summit Investments allocated the SMP Holdings Credit Facility to the Partnership during the common control period.  Borrowings under the SMP Holdings Credit Facility incurred interest at LIBOR or a base rate (as defined in the credit agreement) plus an applicable margin.

In March 2014, Summit Investments repaid the then-outstanding $100.0 million remaining balance on the Term Loan as well as $95.0 million then outstanding under the SMP Revolving Credit Facility.  It wrote off $1.5 million of debt issuance costs in connection with these repayments. In May 2014, Summit Investments borrowed $400.0 million pursuant to the Term Loan accordion and in May 2015, it repaid the then-outstanding remaining balance of the Term Loan accordion and wrote off $0.7 million of debt issuance costs in connection therewith.  The allocation of activity under the SMP Revolving Credit Facility ended concurrent with the closing of the 2016 Drop Down.

 

 

10. FINANCIAL INSTRUMENTS

Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. We maintain our cash and cash equivalents in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk.  

Accounts receivable primarily comprise amounts due for the gathering, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top five customers or counterparties accounted for 62% of total accounts receivable at December 31, 2016, compared with 68% as of December 31, 2015.

Fair Value. The carrying amount of cash and cash equivalents, accounts receivable and trade accounts payable reported on the balance sheet approximates fair value due to their short-term maturities.

The Deferred Purchase Price Obligation's carrying value is its fair value because carrying value represents the present value of the payment expected to be made in 2020. Our calculation of the Deferred Purchase Price

EX 99.3-36

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EXHIBIT 99.3

 

Obligation involves significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a material effect on the ultimate cash payment and the Deferred Purchase Price Obligation. As such, its fair value measurement is classified as a non-recurring Level 3 measurement in the fair value hierarchy because our assumptions and judgments are not observable from objective sources (see Note 16).

The Deferred Purchase Price Obligation represents our only Level 3 financial instrument fair value measurement.  A rollforward of our Level 3 liability measured at fair value on a recurring basis follows.

 

A summary of the estimated fair value of our debt financial instruments follows.

 

(1) Debt was allocated to the 2016 Drop Down Assets prior to the closing of the 2016 Drop Down but was retained by Summit Investments after close.

The carrying value on the balance sheet of each revolving credit facility and the term loan is its fair value due to its floating interest rate. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of December 31, 2016 and 2015. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

 

 

EX 99.3-37

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EXHIBIT 99.3

 

11. PARTNERS' CAPITAL

A rollforward of the number of common limited partner, subordinated limited partner and General Partner units follows.

Unit Offerings.  In March 2014, we completed an underwritten public offering of 10,350,000 common units at a price of $38.75 per unit, of which 5,300,000 common units were offered by the Partnership and 5,050,000 common units were offered by a subsidiary of Summit Investments, pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. Concurrently, our General Partner made a capital contribution to maintain its approximate 2% general partner interest in SMLP.  We used the proceeds from the primary offering and the General Partner capital contribution to fund a portion of the purchase of Red Rock Gathering.  

In September 2014, we completed a secondary underwritten public offering of 4,347,826 SMLP common units held by a subsidiary of Summit Investments pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. We did not receive any proceeds from this offering.

In May 2015, we completed an underwritten public offering of 6,500,000 common units at a price of $30.75 per unit pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC (the "May 2015 Equity Offering"). On May 22, 2015, the underwriters exercised in full their option to purchase an additional 975,000 common units from us at a price of $30.75 per unit. Concurrent with both transactions, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest.

In September 2016, we completed an underwritten public offering of 5,500,000 common units at a price of $23.20 per unit pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC (the "September 2016 Equity Offering").  Following the September 2016 Equity Offering, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest.  We used the net proceeds from the September 2016 Equity Offering to pay down our Revolving Credit Facility.

In January 2017, we completed a secondary underwritten public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. We did not receive any proceeds from this offering.

EX 99.3-38

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EXHIBIT 99.3

 

Subordination.  The subordination period ended in conjunction with the February 2016 distribution payment in respect of the fourth quarter of 2015 and the then-outstanding subordinated units converted to common units on a one-for-one basis.  Prior to the end of the subordination period, the principal difference between our common units and subordinated units was that holders of the subordinated units were not entitled to receive any distribution of available cash until the common units had received the minimum quarterly distribution ("MQD") plus any arrearages in the payment of the MQD from prior quarters.

Noncontrolling Interest.  We have recorded Summit Investments' indirect retained ownership interest in OpCo and its subsidiaries as a noncontrolling interest in the consolidated financial statements.

Summit Investments' Equity in Contributed Subsidiaries.  Summit Investments' equity in contributed subsidiaries represents its position in the net assets of the 2016 Drop Down Assets, Polar and Divide, Red Rock Gathering and Bison Midstream that have been acquired by SMLP. The balance also reflects net income attributable to Summit Investments for the 2016 Drop Down Assets, Polar and Divide, Red Rock Gathering and Bison Midstream for the periods beginning on their respective acquisition dates by Summit Investments and ending on the dates they were acquired by the Partnership.  Net income or loss was attributed to Summit Investments for:

Although included in partners' capital, any net income or loss attributable to Summit Investments is excluded from the calculation of EPU.

2016 Drop Down.  On March 3, 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We paid cash consideration of $360.0 million and recognized a Deferred Purchase Price Obligation of $507.4 million in exchange for Summit Investments' $1.11 billion net investment in the 2016 Drop Down Assets (see Note 16).  In June 2016, we received a working capital adjustment of $0.6 million from a subsidiary of Summit Investments.  We recognized a capital contribution from Summit Investments for the difference between (i) the net cash consideration paid and the Deferred Purchase Price Obligation and (ii) Summit Investments' net investment in the 2016 Drop Down Assets.

The calculation of the capital contribution and its allocation to partners' capital follows (in thousands).

EX 99.3-39

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EXHIBIT 99.3

 

Polar and Divide Drop Down.  On May 18, 2015, we acquired 100% of the membership interests in Polar Midstream and Epping from a subsidiary of Summit Investments. We paid total net cash consideration of $285.7 million in exchange for Summit Investments' $416.0 million net investment in Polar Midstream and Epping, including customary working capital and capital expenditures adjustments (see Note 16 for additional information).  We recognized a capital contribution from Summit Investments for the difference between cash consideration paid and Summit Investments' net investment in Polar Midstream and Epping.

The calculation of the capital contribution and its allocation to partners' capital follow (in thousands).

Red Rock Drop Down.  On March 18, 2014, we acquired 100% of the membership interests in Red Rock Gathering from a subsidiary of Summit Investments. We paid total net cash consideration of $307.9 million (including working capital adjustments accrued in December 2014 and cash settled in February 2015) in exchange for Summit Investments' $241.8 million net investment in Red Rock Gathering.  As a result of the excess of the purchase price over acquired carrying value of Red Rock Gathering, SMLP recognized a capital distribution to Summit Investments.

The calculation of the capital distribution and its allocation to partners' capital follow (in thousands).

Cash Distribution Policy

Our cash distribution policy, as expressed in our Partnership Agreement, may not be modified or repealed without amending our Partnership Agreement. Our Partnership Agreement requires that we distribute all of our available cash (as defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date.  Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the MQD stated in our Partnership Agreement.

EX 99.3-40

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EXHIBIT 99.3

 

General Partner Interest.  Our General Partner is entitled to an equivalent percentage of all distributions that we make prior to our liquidation based on its respective general partner interest, up to a maximum of 2%. 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 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 general partner interest immediately prior to the unit issuance.

Minimum Quarterly Distribution.  Our Partnership Agreement generally requires that we make a minimum quarterly distribution to the holders of our common units of $0.40 per unit, or $1.60 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. The amount of distributions paid under our policy is subject to fluctuations based on the amount of cash we generate from our business and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.

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

Cash Distributions Paid and Declared.  We paid the following per-unit distributions during the years ended December 31:

 

On January 26, 2017, the Board of Directors of our General Partner declared a distribution of $0.575 per unit for the quarterly period ended December 31, 2016.  This distribution, which totaled $44.5 million, was paid on February 14, 2017 to unitholders of record at the close of business on February 7, 2017.

We allocated the February 2017 distribution in accordance with the third target distribution level (see "Incentive Distribution Rights—Percentage Allocations of Available Cash" below for additional information.)

Incentive Distribution Rights.  Our General Partner also currently holds IDRs that entitle it to receive increasing percentage allocations of the cash we distribute from operating surplus (as set forth in the chart below).  The maximum distribution includes distributions paid to our General Partner on an assumed 2% general partner interest. The maximum distribution does not include any distributions that our General Partner may receive on any common units that it owns.

EX 99.3-41

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EXHIBIT 99.3

 

Percentage Allocations of Available Cash.  The following table illustrates the percentage allocations of available cash between the unitholders and our General Partner based on the specified target distribution levels. The amounts set forth in the column Marginal Percentage Interest in Distributions are the percentage interests of our General Partner and the unitholders in any available cash 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 MQD. The percentage interests set forth below for our General Partner assume (i) a 2% general partner interest, (ii) that our General Partner has not transferred its IDRs and (iii) that there are no arrearages on common units.

 

We reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013.  We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014.

Our payment of IDRs as reported in distributions to unitholders – General Partner in the statements of partners' capital during the years ended December 31 follow.

For the purposes of calculating net income attributable to General Partner in the statements of operations and partners' capital, the financial impact of IDRs is recognized in respect of the quarter for which the distributions were declared. For the purposes of calculating distributions to unitholders in the statements of partners' capital and cash flows, IDR payments are recognized in the quarter in which they are paid.

 

 

EX 99.3-42

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EXHIBIT 99.3

 

12. EARNINGS PER UNIT

The following table details the components of EPU.

 

(1) The subordination period ended on February 16, 2016 and all 24,409,850 subordinated units converted to common units on a one-for-one basis (see Note 11).

 

 

13. UNIT-BASED AND NONCASH COMPENSATION

SMLP Long-Term Incentive Plan.  The SMLP LTIP provides for equity awards to eligible officers, employees, consultants and directors of our General Partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The SMLP LTIP is administered by our General Partner's Board of Directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2016, approximately 3.9 million common units remained available for future issuance.

The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the Board of Directors or Compensation Committee of our General Partner. The administrator of the SMLP LTIP may make grants under the SMLP LTIP that contain such terms, consistent with the SMLP LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the SMLP 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 SMLP LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards.  

EX 99.3-43

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EXHIBIT 99.3

 

The following table presents phantom and restricted unit activity:

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. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date.  A restricted unit is a common limited partner unit that is subject to a restricted period during which the unit remains subject to forfeiture.

The phantom units granted in connection with the IPO vested on the third anniversary of the IPO.  All other phantom units granted to date vest ratably over a three-year period. Grant date fair value is determined based on the closing price of our common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at our discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units. The restricted units granted in 2013 maintained the vesting provisions of the share-based compensation awards they replaced, each of which had an original vesting period of four years.

The intrinsic value of phantom and restricted units that vested during the years ended December 31, follows.

As of December 31, 2016, the unrecognized unit-based compensation related to the SMLP LTIP was $5.4 million.  Incremental unit-based compensation will be recorded over the remaining vesting period of approximately 2.2 years. Due to the limited and insignificant forfeiture history associated with the grants under the SMLP LTIP, no forfeitures were assumed in the determination of estimated compensation expense.

EX 99.3-44

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EXHIBIT 99.3

 

Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows.

 

 

 

14. RELATED-PARTY TRANSACTIONS

Acquisitions.  See Notes 1, 9, 11 and 16 for disclosure of the 2016 Drop Down, Polar and Divide Drop Down, the Red Rock Drop Down and the funding of those transactions.

Reimbursement of Expenses from General Partner.  Our General Partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us.  Due to affiliate on the consolidated balance sheet represents the payables to our General Partner for expenses incurred by it and paid on our behalf.

Expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were as follows:

Expenses Incurred by Summit Investments.  Prior to the 2016 Drop Down, the Polar and Divide Drop Down and the Red Rock Drop Down, Summit Investments incurred:

Subsequent to any drop down, these expenses are retrospectively included in the reimbursement of General Partner expenses disclosed above due to common control.

 

EX 99.3-45

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EXHIBIT 99.3

 

15. COMMITMENTS AND CONTINGENCIES

Operating Leases.  We and Summit Investments lease certain office space to support our operations.  We have determined that our leases are operating leases. We recognize total rent expense incurred or allocated to us in general and administrative expenses. Rent expense related to operating leases, including rent expense incurred on our behalf and allocated to us, was as follows:

 

We lease office space and equipment under agreements that expire in various years through 2021. Future minimum lease payments due under noncancelable operating leases at December 31, 2016, were as follows (in thousands):

Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.

Environmental Matters. Although we believe that we are in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, we can provide no assurances that significant environmental remediation costs and liabilities will not be incurred by the Partnership in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below.

In January 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The rupture resulted in the release of some of the produced water in the pipeline.  Based on Summit Investments' investigation and then-available information, it accounted for the rupture as a 2014 event.

Summit Investments took action to minimize the impact of the rupture on affected landowners, control any environmental impact, help ensure containment and clean up the affected area.  The incident, which was covered by Summit Investments' insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy.  Summit Investments exhausted the $25.0 million pollution liability policy in 2015.  We submitted property and business interruption claim requests to the insurers and reached a settlement in January 2017.  In connection therewith, we recognized $2.6 million of business interruption recoveries and $0.4 million of property recoveries.

EX 99.3-46

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EXHIBIT 99.3

 

A rollforward of the aggregate accrued environmental remediation liabilities follows.

As of December 31, 2016, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to December 31, 2017.  Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

The U.S. Department of Justice has issued subpoenas to Summit Investments, Meadowlark Midstream, the Partnership and our General Partner requesting certain materials related to the rupture.  We cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident.  SMLP and its General Partner did not have any management or operational control over, or ownership interest in, Meadowlark Midstream or the produced water disposal pipeline prior to the 2016 Drop Down. Furthermore, the Contribution Agreement executed in connection with the 2016 Drop Down contains customary representations and warranties and Summit Investments has agreed to indemnify the Partnership with respect to certain losses, including losses related to the rupture.  As a result, we believe at this time that it is unlikely that SMLP or its General Partner will be subject to any material liability as a result of any governmental proceeding related to the rupture.

In June 2015, Summit Investments and Meadowlark Midstream received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees related to the rupture.  Meadowlark Midstream has accrued its best estimate of the amount to be paid for such fines and other fees and intends to vigorously defend this complaint.

 

 

16. ACQUISITIONS AND DROP DOWN TRANSACTIONS

2016 Drop Down. On March 3, 2016, SMLP acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets.  These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin as well as ownership interests in a natural gas gathering system and a condensate stabilization facility, both located in the Utica Shale.

The net consideration paid and recognized in connection with the 2016 Drop Down (i) consisted of a cash payment to SMP Holdings of $360.0 million funded with borrowings under our Revolving Credit Facility and a $0.6 million working capital adjustment received in June 2016 (the “Initial Payment”) and (ii) includes the Deferred Purchase Price Obligation payment due in 2020. 

The Deferred Purchase Price Obligation will be equal to:

EX 99.3-47

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EXHIBIT 99.3

 

Business Adjusted EBITDA is defined as the net income or loss of the 2016 Drop Down Assets for such period:

Business Adjusted EBITDA shall exclude the effect of any Partnership expenses allocated by or to SMLP or its affiliates in respect of the 2016 Drop Down Assets, such as general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, allocated interest expense and allocated income tax expense.

Special Liability Expenses are defined as any and all expenses incurred by SMLP with respect to the Special Liabilities, as defined in the Contribution Agreement, including fines, legal fees, consulting fees and remediation costs.

The present value of the Deferred Purchase Price Obligation will be reflected as a liability on our balance sheet until paid.  As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets) was estimated to be $860.3 million and had a net present value of $507.4 million, using a discount rate of 13%.  As of December 31, 2016, Remaining Consideration was estimated to be $830.3 million and the net present value, as recognized on the consolidated balance sheet, was $563.3 million, using a discount rate of 12%.  Any subsequent changes to the estimated future payment obligation will be calculated using a discounted cash flow model with a commensurate risk-adjusted discount rate.  Such changes and the impact on the liability due to the passage of time will be recorded as Deferred Purchase Price Obligation income or expense on the consolidated statements of operations in the period of the change.

At the discretion of the Board of Directors of our General Partner, the Deferred Purchase Price Obligation can be paid in cash, SMLP common units or a combination thereof.  We currently expect that the Deferred Purchase Price Obligation will be financed with a combination of (i) net proceeds from the sale of common units by us, (ii) the net proceeds from the issuance of senior unsecured debt by us, (iii) borrowings under our Revolving Credit Facility and/or (iv) other internally generated sources of cash.

Because of the common control aspects in a drop down transaction, the 2016 Drop Down was deemed a transaction between entities under common control.  As such, the 2016 Drop Down has been accounted for on an “as-if pooled” basis for all periods in which common control existed and the Partnership’s financial results retrospectively include the combined financial results of the 2016 Drop Down Assets for all common-control periods.

Summit Utica.  Summit Investments completed the acquisition of certain natural gas gathering assets located in the Utica Shale Play for $25.2 million on December 15, 2014. These assets, which were contributed to Summit Investments' then-newly formed subsidiary, Summit Utica, gather natural gas under a long-term, fee-based contract. Summit Investments accounted for the purchase under the acquisition method of accounting.  We assigned the full purchase price to property, plant and equipment as of December 31, 2014.

Ohio Gathering.  For information on the acquisition and initial recognition of Ohio Gathering, see Note 7.

EX 99.3-48

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EXHIBIT 99.3

 

Meadowlark Midstream.  At the time of the 2016 Drop Down, Meadowlark Midstream owned Niobrara G&P and certain crude oil and produced water gathering pipelines located in Williams County, North Dakota.  Summit Investments accounted for its purchase of Meadowlark Midstream under the acquisition method of accounting, whereby the various gathering systems' identifiable tangible and intangible assets acquired and liabilities assumed were recorded based on their fair values as of initial acquisition on February 15, 2013. Both Bison Midstream and Polar Midstream have previously been carved out of Meadowlark Midstream.  Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives and projected capital expenditures to complete the system. We recognized the 2016 acquisition of Meadowlark Midstream at Summit Investments' historical cost of construction and fair value of assets and liabilities at acquisition, which reflected its fair value accounting for the initial acquisition of Meadowlark Midstream in 2013, due to common control.

The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands):

From a financial position and operational standpoint, the crude oil and produced water gathering pipelines held by Meadowlark Midstream and acquired in connection with the 2016 Drop Down are recognized as part of the Polar and Divide system.

Polar and Divide.  On May 18, 2015, SMLP acquired the Polar and Divide system, a crude oil and produced water gathering system, including under-development transmission pipelines, located in North Dakota from a subsidiary of Summit Investments, subject to customary working capital and capital expenditures adjustments. We funded the initial combined purchase price of $290.0 million with (i) $92.0 million of borrowings under SMLP’s Revolving Credit Facility and (ii) the issuance of $193.4 million of SMLP common units and $4.1 million of general partner interests to SMLP’s General Partner in connection with the May 2015 Equity Offering. In July 2015, we received $4.3 million of cash from a subsidiary of Summit Investments as payment in full for working capital and capital expenditure adjustments.

Summit Investments accounted for its purchase of Meadowlark Midstream, the entity that Polar Midstream was carved out of, under the acquisition method of accounting, whereby the various gathering systems' identifiable tangible and intangible assets acquired and liabilities assumed were recorded based on their fair values as of initial acquisition on February 15, 2013. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives and projected capital expenditures to complete the system. We recognized the acquisition of Polar Midstream at Summit Investments' historical cost of construction and fair value of assets and liabilities at acquisition, which reflected its fair value accounting for the acquisition of Meadowlark Midstream, due to common control.

EX 99.3-49

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EXHIBIT 99.3

 

The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands):

We believe that the goodwill recorded represents the incremental value of future cash flow potential attributed to estimated future gathering services within the Williston Basin.

Red Rock Gathering System.  On March 18, 2014, SMLP acquired Red Rock Gathering, a natural gas gathering and processing system located in Colorado and Utah, from a subsidiary of Summit Investments, subject to customary working capital adjustments. In October 2012, Summit Investments acquired ETC Canyon Pipeline, LLC ("Canyon") and contributed the Canyon gathering and processing assets to Red Rock Gathering, a newly formed, wholly owned subsidiary of Summit Investments. The Partnership paid total cash consideration of $307.9 million, comprising $305.0 million at the date of acquisition and $2.9 million of working capital adjustments that were recognized in due to affiliate as of December 31, 2014 and settled in February 2015. The acquisition of Red Rock Gathering was funded with the net proceeds from an offering of common units in March 2014, $100.0 million of borrowings under our Revolving Credit Facility and cash on hand.  Because of the common control aspects in the drop down transaction, the Red Rock Gathering acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as-if pooled” basis for all periods in which common control existed.  SMLP’s financial results retrospectively include Red Rock Gathering’s financial results for all periods ending after October 23, 2012, the date Summit Investments acquired its interests, and before March 18, 2014.

In 2014, we identified and wrote off the balance associated with a working capital adjustment received after the purchase accounting measurement period closed for Summit Investments' acquisition of Red Rock Gathering. This write off was recognized as a $1.2 million increase to gathering services and other fees for the year ended December 31, 2014.

Lonestar Assets.  DFW Midstream completed the acquisition of certain natural gas gathering assets located in the Barnett Shale Play (the "Lonestar assets") from Texas Energy Midstream, L.P. ("TEM") for $10.9 million on September 30, 2014. The Lonestar assets gather natural gas under two long-term, fee-based contracts. SMLP accounted for the purchase under the acquisition method of accounting. As of September 30, 2014, we preliminarily assigned the full purchase price to property, plant and equipment. During the fourth quarter of 2014, we received additional information from TEM and finalized the purchase price allocation.

EX 99.3-50

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EXHIBIT 99.3

 

Supplemental Disclosures – As-If Pooled Basis.  As a result of accounting for our drop down transactions similar to a pooling of interests, our historical financial statements and those of the acquired drop down assets have been combined to reflect the historical operations, financial position and cash flows of the acquired drop down assets from the date common control began. Revenues and net income for the previously separate entities and the combined amounts, as presented in these consolidated financial statements follow.

 

(1) Results are fully reflected in SMLP's results of operations subsequent to closing the respective drop down.

 

 

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In July 2014 and June 2013, the Co-Issuers issued the Senior Notes. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 9).

The following supplemental condensed consolidating financial information reflects SMLP's separate accounts, the combined accounts of the Co-Issuers, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries and the consolidating adjustments for the dates and periods indicated.  For purposes of the following consolidating information:

 

EX 99.3-51

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EXHIBIT 99.3

 

Condensed Consolidating Balance Sheets.  Balance sheets as of December 31, 2016 and 2015 follow.

 

EX 99.3-52

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EXHIBIT 99.3

 

 

 

EX 99.3-53

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EXHIBIT 99.3

 

Condensed Consolidating Statements of Operations.  For the purposes of the following condensed consolidating statements of operations, we allocate general and administrative expenses recognized at the SMLP parent to the Guarantor Subsidiaries and Non-Guarantor Subsidiaries to reflect what those entities' results would have been had they operated on a stand-alone basis.  Statements of operations for the years ended December 31, 2016, 2015 and 2014 follow.

 

EX 99.3-54

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EXHIBIT 99.3

 

 

 

EX 99.3-55

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EXHIBIT 99.3

 

 

 

 

EX 99.3-56

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EXHIBIT 99.3

 

Condensed Consolidating Statements of Cash Flows.  Statements of cash flows for the years ended December 31, 2016, 2015 and 2014 follow.

 

EX 99.3-57

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EXHIBIT 99.3

 

 

EX 99.3-58

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EXHIBIT 99.3

 

 

EX 99.3-59

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EXHIBIT 99.3

 

 

 

 

EX 99.3-60

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EXHIBIT 99.3

 

18. UNAUDITED QUARTERLY FINANCIAL DATA

Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2016, follows.

 

 

(1) Retrospectively adjusted for the impact of the 2016 Drop Down, the Polar and Divide Drop Down and the reclassification of certain revenues for Bison Midstream.

(2) In the quarter ended December 31, 2015, net loss attributable to SMLP includes $248.9 million of goodwill impairments and $1.6 million of long-lived asset impairments.

(3) In the quarter ended September 30, 2015, net income attributable to SMLP includes $20.0 million of additional accruals for environmental remediation expenses and $7.7 million of long-lived asset impairments.

EX 99.3-61

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EXHIBIT 99.3

 

The amounts for total revenues as originally filed on the respective 2015 quarterly reports on Form 10-Q have been retrospectively adjusted for the impact of the 2016 Drop Down, Polar and Divide Drop Down and reclassification of certain revenues for Bison Midstream.  There was no impact on net income attributable to partners or EPU.  A reconciliation of total revenues follows.

 

 

 

EX 99.3-62