8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

(Amendment No. 1)

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): September 1, 2016 (June 6, 2016)

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)

Delaware	001-35666	45-5200503
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation)	File Number)	Identification No.)

1790 Hughes Landing Blvd

Suite 500

The Woodlands, TX 77380

(Address of principal executive offices) (Zip Code)

Registrants’ 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:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EXPLANATORY NOTE

The purpose of this Amendment No. 1 to our Current Report on Form 8-K, originally filed with the Securities and Exchange Commission (“SEC”) on June 6, 2016 (the “Original Filing”), which updated and superseded our Annual Report on Form 10-K dated February 29, 2016 (as updated and superseded by the Original Filing, the "2015 Annual Report"), is to include additional disclosure required in a footnote to our consolidated financial statements under Rule 3-10 of Regulation S-X ("Rule 3-10"). The additional disclosure results from a change in the guarantor structure of the Senior Notes (as defined in Note 9 to the consolidated financial statements) in connection with our March 2016 purchase of an interest in 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 "2016 Drop Down").

The following items of the 2015 Annual Report are being retrospectively adjusted to reflect the 2016 Drop Down and our interest in the financial results of the acquired assets for all periods during which common control existed:

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

• Item 8. Financial Statements and Supplementary Data.

These items replace the same items filed in our 2015 Annual Report. 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 2015 Annual Report. More current information is contained in our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016 and our other filings with the SEC.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

Exhibit number		Description
23.1		Consent of Deloitte & Touche LLP
99.1		Updated 2015 Annual Report on Form 10-K - Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
99.2		Updated 2015 Annual Report on Form 10-K - Item 8. Financial Statements and Supplementary Data.
101.INS	**	XBRL Instance Document (1)
101.SCH	**	XBRL Taxonomy Extension Schema
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	XBRL Taxonomy Extension Label Linkbase
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase

** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL(eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.

(1) Includes the following materials contained in this Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Partners' Capital, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.

1

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.

	Summit Midstream Partners, LP
	(Registrant)
	By:	Summit Midstream GP, LLC (its general partner)
September 1, 2016	/s/ Matthew S. Harrison
	Matthew S. Harrison, Executive Vice President and Chief Financial Officer

2

EXHIBIT INDEX

Exhibit number	Description
23.1	Consent of Deloitte & Touche LLP
99.1	Updated 2015 Annual Report on Form 10-K - Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
99.2	Updated 2015 Annual Report on Form 10-K - Item 8. Financial Statements and Supplementary Data.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

3

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-197311 and 333-191493 on Form S-3 and Nos. 333-184214 and 333-189684 on Form S-8 of our report dated February 26, 2016 (June 6, 2016 as to the effects of the 2016 Drop Down as described in Notes 1 and 16, and the retrospective application of the change in accounting policy for presentation of debt issuance costs as described in Note 1; September 1, 2016 as to the addition of disclosures in Note 17 required under Regulation S-X Rule 3-10 as a result of the 2016 Drop Down, and the change in the guarantor structure of the Senior Notes described in Note 9), relating to the consolidated financial statements of Summit Midstream Partners, LP and subsidiaries (the "Partnership") (which report expresses an unqualified opinion and includes an explanatory paragraph regarding the retrospective adjustment for the acquisition of Summit Midstream Utica, LLC, Meadowlark Midstream Company, LLC, Tioga Midstream, LLC, and the 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. from Summit Midstream Partners Holdings, LLC which was accounted for as a combination of entities under common control), appearing in this Amendment No.1 to the Current Report on Form 8-K of Summit Midstream Partners, LP.

/s/ DELOITTE & TOUCHE LLP

Atlanta, Georgia

September 1, 2016

EX 23.1-1

EX-99.1

EXHIBIT 99.1

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

• Trends and Outlook

• How We Evaluate Our Operations

• Results of Operations

• Non-GAAP Financial Measures

• Liquidity and Capital Resources

• Critical Accounting Estimates

• Forward-Looking Statements

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

• the Utica Shale, which includes our ownership interest in Ohio Gathering and also is served by Summit Utica;

• the Williston Basin, which is served by Bison Midstream, Polar and Divide, and Tioga Midstream;

• the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;

• the Barnett Shale, which is served by DFW Midstream;

• the Marcellus Shale, which is served by Mountaineer Midstream.

Our results are driven primarily by the volumes that we gather, treat and/or process. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas customers. Under the substantial majority of these agreements, we are paid a fixed fee based on the volumes we gather, treat and/or process. These agreements enhance the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk.

We also earn revenue from (i) crude oil and produced water gathering, (ii) 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 gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. We are exposed to direct commodity price risk from engaging in any of these additional activities with the exception of crude oil and produced water gathering. We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay 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 or natural gas) that we gather. If our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, our MVCs ensure that we will receive a certain amount of revenue from certain of our customers.

EX 99.1-1

EXHIBIT 99.1

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

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Selected Financial Results:
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008
EBITDA (1)	(57,838		)	93,890			141,310
Adjusted EBITDA (1)	235,491			207,975			162,690
Distributable cash flow (1)	164,931			144,711			120,611
Acquisitions of gathering systems (2)	$	288,618		$	315,872		$	458,914
Capital expenditures (3)	(272,225		)	(343,380		)	(249,626		)
Proceeds from issuance of common units, net (4)	$	221,977		$	197,806		$	—
Issuance of senior notes	—			300,000			300,000
Borrowings (repayments) under revolving credit facility, net	216,000			(136,000		)	179,770
Distributions to unitholders	(152,074		)	(122,224		)	(90,196		)

__________

(1) See "Non-GAAP Financial Measures" herein for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.

(2) Reflects consideration paid, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs. For additional information, see Note 16 to the consolidated financial statements.

(3) See "Liquidity and Capital Resources" herein for additional information on capital expenditures.

(4) Reflects proceeds from underwritten primary offerings and does not include proceeds from units issued to affiliates to affect acquisitions or drop downs.

Year ended December 31, 2015. After a slight pause mid-year 2015, crude oil and NGL prices continued to decline in response to the global supply surplus. As a result, several of the producers in our areas of operations announced plans to cancel, delay and/or reduce drilling plans which in turn negatively impacted the margins that we earn, slowing the growth in net income and adjusted EBITDA. In addition to impacting the margins that we earn and net income, the goodwill that we had previously recognized in connection with our acquisitions of Polar and Divide and Grand River was determined to be fully impaired, resulting in a write-off of $248.9 million.

During 2015, we acquired Polar and Divide from a subsidiary of Summit Investments in a drop down transaction. We also began and/or completed system expansion projects on the Polar and Divide, Grand River, Bison Midstream and Tioga Midstream systems.

In May 2015, we completed an underwritten primary offering of common units and used the proceeds along with borrowings under our revolving credit facility to fund the Polar and Divide Drop Down. Distributions declared in respect of the fourth quarter of 2015 increased 2.7% over distributions declared in respect of the fourth quarter of 2014.

Year ended December 31, 2014. In the second half of 2014, crude oil and NGL prices began to decline, negatively impacting producers in each of our areas of operation. The impact of these declines were most evident in our North Dakota operations where our percentage of fee-based gathering agreements is less than that of our other systems. In addition to impacting the margins that we earned, the goodwill that we had previously recognized in connection with our acquisition of Bison Midstream was determined to be fully impaired, resulting in a write-off of $54.2 million.

During 2014, we acquired Red Rock Gathering from a subsidiary of Summit Investments in a drop down transaction. We also completed several system expansion projects across all systems.

In March 2014, we completed an underwritten public offering of primary and secondary units and we also completed a secondary offering in September 2014. We used the funds from the March 2014 primary offering to partially fund the Red Rock Drop Down. In July 2014, we also issued senior notes and used the proceeds to repay a portion of our outstanding revolving credit facility balance. Distributions declared in respect of the fourth quarter of 2014 increased 16.7% over distributions declared in respect of the fourth quarter of 2013.

EX 99.1-2

EXHIBIT 99.1

Year ended December 31, 2013. During 2013, we acquired Bison Midstream from a subsidiary of Summit Investments in a drop down transaction and Mountaineer Midstream in a third-party acquisition. We also completed several system expansion projects across all systems.

In June 2013, we issued senior notes and common units to Summit Investments to fund the acquisitions of Bison Midstream and Mountaineer Midstream. Distributions declared in respect of the fourth quarter of 2013 increased 17.1% over distributions declared in respect of the fourth quarter of 2012.

For additional information, see Item 1. Business, the remainder of this MD&A and the notes to the consolidated financial statements included herein.

Trends and Outlook

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

• Natural gas, NGL and crude oil supply and demand dynamics;

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

• Capital markets activity and cost of capital;

• Acquisitions from third parties; and

• Shifts in operating costs and inflation.

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 has decreased, with the New York Mercantile Exchange, or NYMEX, natural gas futures price at $2.28 per MMBtu as of December 31, 2015 compared with $2.89 per MMBtu as of December 31, 2014 and $4.23 per MMBtu as of December 31, 2013. Natural gas prices continue to trade at lower-than-average historical prices due in part to increased production, especially from unconventional sources, such as natural gas shale plays. According to the U.S. Energy Information Administration (the "EIA"), average annual natural gas production in the United States increased to 85.9 Bcf/d, or 55.9%, in 2014 from 55.1 Bcf/d in 2008. Over the same time period, natural gas consumption increased only 15.0% to 73.1 Bcf/d. In response to lower natural gas prices, the number of active natural gas drilling rigs has declined from approximately 1,350 in December 2008 to approximately 162 in December 2015, according to Baker Hughes.

Lower natural gas prices in 2015 relative to 2014 and 2013 are also attributable to U.S. weather patterns that contributed to temperatures that were 24% warmer than historical norms in the second half of 2015, which resulted in lower-than-normal overall consumption of natural gas. As a result, the amount of natural gas in storage in the continental United States increased to approximately 3.8 Tcf as of December 25, 2015, compared with approximately 3.2 Tcf as of December 26, 2014, and a five-year historical December average of 3.5 Tcf. Additionally, a number of exploration and production companies made public announcements in 2015 regarding abnormally high production rates from natural gas wells targeting the Utica Shale formation in Ohio, West Virginia and Pennsylvania, which has resulted in a recalibration of the market’s expectation for future natural gas supplies in the United States.

We believe that over the near term, until the supply of natural gas has been reduced, weather patterns change, resulting in colder temperatures, or the broader economy experiences more robust growth to stimulate higher demand, natural gas prices are likely to be constrained.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. For example, according to the EIA, coal-fired power plants generated 39% of the electricity in the United States in 2014, compared with 48% in 2008. The EIA expects this trend to continue, with coal-fired power plants representing 34% of total electricity generation by 2040.

In April 2015, the EIA projected total annual domestic consumption of natural gas to increase from approximately 71.8 Bcf/d in 2013 to approximately 81.4 Bcf/d in 2040. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2040 to 97.3 Bcf/d. The EIA also projects that the United States will be a net exporter of liquefied natural gas, or LNG, by 2017, with net U.S. exports of LNG

EX 99.1-3

EXHIBIT 99.1

projected to rise to 15.3 Bcf/d in 2040, compared with net imports of 4.1 Bcf/d in 2013. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the United States.

In addition, the Bison Midstream, Polar and Divide, Niobrara G&P and Tioga Midstream systems are directly affected by crude oil supply and demand dynamics. Crude oil has been the focus of a recent global supply surplus, with OPEC initially stating in November 2014 and throughout 2015 that it would not decrease production levels, despite concerns of slowing global demand, particularly in historically high growth countries such as China. This, in conjunction with continued crude oil production growth from unconventional shale plays in the United States, and expected crude oil production growth in countries that have had limited production outputs of late, such as Iran, has played a significant role in the recent decline in crude oil prices, with NYMEX crude oil futures ending 2015 at $37.13 per barrel, compared to a high in June 2014 of $107.26 per barrel. In response to lower crude oil prices, the number of active crude oil drilling rigs has declined from a peak of 1,609 in October 2014 to 536 in December 2015, according to Baker Hughes. For additional information, see the "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" section herein and Notes 4, 5 and 6 to the consolidated financial statements.

Over the next several years, the EIA projects that domestic crude oil production will continue to increase from an average of 8.7 million Bbl/d in 2014 to 10.6 million Bbl/d in 2020. While long-term estimates vary due to uncertainty regarding long-term crude oil price trends, the EIA still sees continued growth in certain unconventional shale plays, with crude oil prices expected to remain high enough to support continued drilling and increasing production in the Bakken Shale, Eagle Ford Shale, Permian Basin, and Niobrara Shale. Additionally, in December 2015, the United States lifted a ban that had previously prohibited crude oil exports. This repeal should, over time, enable the West Texas Intermediate ("WTI") crude oil price benchmark to become more competitive with other global crude oil price benchmarks, thus stimulating incremental domestic production.

Growth in production from U.S. shale plays.Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional shale resources. While the EIA expects total dry natural gas production to grow 38.1% from 25.7 Tcf in 2014 to 35.5 Tcf in 2040, it expects shale gas production to grow to 19.6 Tcf in 2040, representing 55% of total U.S. natural gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per-unit economics when compared to most conventional plays.

In recent years, producers have leased large acreage positions in the areas in which we operate and other unconventional resource plays. To help fund their drilling programs in many of these areas, a number of producers have entered into joint venture arrangements with large international operators, industrial manufacturers and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin and the Barnett, Bakken and Marcellus shale plays and other unconventional resource plays, which we believe will support sustained drilling activity.

As a result of the current low commodity price environment, many producers have announced reductions to their capital expenditure budgets by limiting their drilling activities in lower performing resource plays or in lower tier areas within higher performing resource plays. In addition, the low commodity price environment has left a number of producers in financial distress, evidenced in part by the 31 U.S.-based exploration and production companies that filed for bankruptcy protection in 2015. Nevertheless, we believe producers will remain focused on deploying capital in their highest quality resource plays, even in a low commodity price environment.

Capital markets activity and cost of capital.After multiple years of near-record low interest rates, the credit markets reversed in 2015 and borrowing costs increased for virtually all crude oil and natural gas industry-related borrowers. Additionally, in December 2015, the Federal Reserve announced that it would raise its benchmark federal-funds rate from near zero to a range between 0.25% and 0.50%, the first such increase since 2006. 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 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 competitors would face similar circumstances.

Acquisitions from Third Parties. 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 make acquisitions that increase the amount of cash generated from our operations on a per-unit basis, along with other

EX 99.1-4

EXHIBIT 99.1

factors. Following the 2016 Drop Down, we intend to continue to pursue accretive acquisitions of midstream assets from third parties. However, their size, timing and/or contribution to our results of operations 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 on acceptable terms 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 on acceptable terms from commercial banks, the capital markets or other sources.

The acquisition component of our principal business strategy has required and will continue to require significant expenditures by us as well as access to external sources of financing from the debt and equity capital markets. Furthermore, as our Sponsor and Summit Investments are under no obligation to provide any direct or indirect financial assistance to us, 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. Any prospective third-party transaction would be impacted by our ability to obtain financing on acceptable terms from the capital markets or other sources, among other factors.

We expect to finance potential third-party acquisitions with equity offerings and borrowings under our revolving credit facility, initially. Longer-term financing is expected to be provided by the issuance of additional debt and equity securities. See the "Liquidity and Capital Resources—Capital Requirements" section herein and Notes 9 and 11 to the consolidated financial statements for additional information.

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 as overall demand for these goods and services declined. 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 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 five reportable segments:

• the Utica Shale, which includes our ownership interest in Ohio Gathering as well as Summit Utica;

• the Williston Basin, which includes Bison Midstream, Polar and Divide and Tioga Midstream;

• the Piceance/DJ Basins, which includes Grand River and Niobrara G&P;

• the Barnett Shale, which includes DFW Midstream;

• the Marcellus Shale, which includes Mountaineer Midstream.

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 for additional information.

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,

• revenues,

• operation and maintenance expenses,

• EBITDA,

• adjusted EBITDA and segment adjusted EBITDA, and

• distributable cash flow.

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.

EX 99.1-5

EXHIBIT 99.1

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.

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:

• successful drilling activity within our AMIs;

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

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

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

• our ability to gather, treat and/or process production that has been released from commitments with our competitors.

We report volumes gathered for natural gas in cubic feet; natural gas gathering rates are reported in millions of cubic feet per day ("MMcf/d"). We aggregate crude oil and produced water gathering and report it in barrels; liquids gathering rates are reported in thousands of barrels per day ("Mbbl/d").

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. We report throughput rates for natural gas on a per thousand cubic feet ("Mcf") basis and throughput rates for liquids on a per barrel ("Bbl") basis.

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.

The majority of the compressors on our DFW Midstream system are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream system customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. With respect to the Mountaineer Midstream, Bison Midstream and Grand River systems, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compressors.

EBITDA, Adjusted EBITDA, Segment Adjusted EBITDA and Distributable Cash Flow

EBITDA, adjusted EBITDA, segment adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others.

EBITDA and adjusted EBITDA (including segment adjusted EBITDA) are used to assess:

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

EX 99.1-6

EXHIBIT 99.1

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

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

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

In addition, adjusted EBITDA (including segment adjusted EBITDA) is used to assess:

• the financial performance of our assets without regard to the impact of (i) income or loss from equity method investees, (ii) the impact of the timing of MVC shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.

Distributable cash flow is used to assess:

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

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

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:

• The consolidated financial statements reflect the results of operations of Summit Utica since December 2014. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

• The consolidated financial statements reflect the results of operations of Tioga Midstream since April 2014. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

• The consolidated financial statements reflect the results of operations of Ohio Gathering since January 2014. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

• The consolidated financial statements reflect the results of operations of Bison Midstream, Polar and Divide and Niobrara G&P since February 2013. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

• The consolidated financial statements reflect the results of operations of Mountaineer Midstream since June 2013.

For additional information, see the "Results of Operations" and "Non-GAAP Financial Measures" sections 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 natural gas liquids purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River.

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.

EX 99.1-7

EXHIBIT 99.1

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 purchased from certain of our customers on the Bison Midstream and Grand River gathering 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. Operation and maintenance also includes our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system.

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.

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

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

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

Interest expense. Interest expense associated with our revolving credit facility, our senior notes and debt that was allocated to the 2016 Drop Down Assets (see Notes 2 and 9 to the consolidated financial statements).

Income tax expense. Since we are structured as a partnership, we are generally not subject to federal and state income taxes, except the Texas Margin Tax, which is reflected herein.

EX 99.1-8

EXHIBIT 99.1

Consolidated Overview of the Years Ended December 31, 2015, 2014 and 2013

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

	Year ended December 31,									Percentage Change
	2015			2014			2013			2015 v. 2014		2014 v. 2013
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	337,819		$	267,478		$	216,352		26	%	24	%
Natural gas, NGLs and condensate sales	42,079			97,094			88,185			(57	)%	10	%
Other revenues	20,659			22,597			21,623			(9	)%	5	%
Total revenues	400,557			387,169			326,160			3	%	19	%
Costs and expenses:
Cost of natural gas and NGLs	31,398			72,415			68,037			(57	)%	6	%
Operation and maintenance	94,986			94,869			78,175			—	%	21	%
General and administrative	45,108			43,281			36,716			4	%	18	%
Transaction costs	1,342			2,985			2,841			(55	)%	5	%
Depreciation and amortization	105,117			90,878			71,232			16	%	28	%
Environmental remediation	21,800			5,000			—			*		*
(Gain) loss on asset sales, net	(172		)	442			113			*		*
Long-lived asset impairment	9,305			5,505			—			69	%	*
Goodwill impairment	248,851			54,199			—			*		*
Total costs and expenses	557,735			369,574			257,114			51	%	44	%
Other income	2			1,189			5			*		*
Interest expense	(59,092		)	(48,586		)	(21,314		)	22	%	128	%
(Loss) income before income taxes	(216,268		)	(29,802		)	47,737			*		*
Income tax benefit (expense)	603			(854		)	(729		)	*		17	%
Loss from equity method investees	(6,563		)	(16,712		)	—			(61	)%	*
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008		*		*
Operating Data:
Aggregate average throughput – gas (MMcf/d)	1,498			1,423			1,139			5	%	25	%
Aggregate average throughput rate per Mcf – gas	$	0.47		$	0.47		$	0.50		—	%	(6	)%
Average throughput – liquids (Mbbl/d)	67.7			40.7			10.9			66	%	*
Average throughput rate per Bbl – liquids	$	1.84		$	1.69		$	0.95		9	%	78	%

__________

* Not considered meaningful

Volumes – Gas. For the year ended December 31, 2015, our aggregate natural gas throughput volumes increased primarily reflecting an increase in volume throughput for Mountaineer Midstream and Summit Utica, partially offset by volume throughput declines on Grand River.

For the year ended December 31, 2014, our aggregate natural gas throughput volumes increased largely reflecting the contribution from Mountaineer Midstream and Grand River. These production increases were partially offset by volume throughput declines on the DFW Midstream and Legacy Grand River systems.

Volumes – Liquids. Average daily throughput for crude oil and produced water increased during the years ended December 31, 2015 and 2014, primarily reflecting the continued development of the Polar and Divide and Tioga Midstream systems, new pad site connections and producers' ongoing drilling activity.

EX 99.1-9

EXHIBIT 99.1

Revenues. For the year ended December 31, 2015, total revenues increased $13.4 million primarily reflecting:

• the recognition in 2015 of previously deferred revenue at Grand River (see Note 8 to the consolidated financial statements).

• an increase in gathering services and related fees for the Polar and Divide, Mountaineer Midstream, Summit Utica and Tioga Midstream systems.

• an offset to revenues as a result of declines in natural gas, NGLs and condensate sales for Bison Midstream, Grand River and DFW Midstream.

For the year ended December 31, 2014, total revenues increased $61.0 million, or 19%, primarily reflecting:

• overall growth at Grand River and Polar and Divide.

• an increase in gathering services and related fees at Mountaineer Midstream due in large part to the partial year of ownership in 2013.

• gathering services and related fees at Tioga Midstream, which was brought into service in November 2014.

• overall growth at Bison Midstream primarily due to higher volume throughput.

• an overall decline in DFW Midstream revenues largely due to lower volume throughput.

Gathering Services and Related Fees. The increase in gathering services and related fees during the year ended December 31, 2015 was primarily driven by the recognition of previously deferred revenue noted above and higher volume throughput on the Polar and Divide, Mountaineer Midstream, Summit Utica and Tioga Midstream systems.

The aggregate average throughput rate for natural gas was flat at $0.47/Mcf during the years ended December 31, 2015 and 2014, primarily as a result of Tioga Midstream's contribution, partially offset by a larger proportion of gathering fee revenue from Mountaineer Midstream. The aggregate average throughput rate for crude oil and produced water increased to $1.84/Bbl during the year ended December 31, 2015, compared with $1.69/Bbl in the prior-year period primarily as a result of the effect of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

For the year ended December 31, 2014, gathering services and related fees increased primarily reflecting the proportionate contribution of higher margin volume throughput from certain customers and the first quarter 2014 commissioning of a natural gas processing plant at Grand River; the impact of higher volume throughput on gathering services and related fees and higher gathering rates associated with contract amendments in 2014 for Polar and Divide; a full year of operations under SMLP's ownership as well as our build out of the Mountaineer Midstream system and the partial year of operations for Tioga Midstream. These increases were partially offset by the continued natural decline in volumes and lack of producer drilling activity on the DFW Midstream system.

The aggregate average throughput rate for natural gas decreased to $0.47/Mcf during the year ended December 31, 2014, compared with $0.50/Mcf in the prior-year period largely as a result of a larger proportion of gathering fee revenue from Mountaineer Midstream, partially offset by an increase for Grand River due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.69/Bbl during the year ended December 31, 2014, compared with $0.95/Bbl in the prior-year period primarily as a result of the effect of 2014 contract amendments noted above.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the year ended December 31, 2015 was primarily a result of the impact of declining commodity prices. Declining commodity prices negatively impacted our percent-of-proceeds arrangements at Bison Midstream and Grand River, our fuel retainage revenue at DFW Midstream and condensate revenue for Grand River.

The increase in natural gas, NGLs and condensate sales for the year ended December 31, 2014 was primarily a result of increased volumes under percent-of-proceeds arrangements at Bison Midstream, partially offset by declining commodity prices.

Costs and Expenses. Total costs and expenses increased $188.2 million, or 51%, for the year ended December 31, 2015 primarily reflecting:

• the goodwill impairments recognized for Polar and Divide and Grand River.

• a partial offset resulting from lower cost of natural gas and NGLs at Bison Midstream and Grand River.

• a full year of operations for Summit Utica and Tioga Midstream.

EX 99.1-10

EXHIBIT 99.1

• an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

• an increase in depreciation and amortization expense for all systems, except DFW Midstream.

• a partial offset due to the impact of the 2014 goodwill and long-lived asset impairments.

For the year ended December 31, 2014, total costs and expenses increased $112.5 million, or 44%, primarily reflecting:

• the goodwill impairment recognized for Bison Midstream.

• an increase in depreciation and amortization across our gathering systems.

• an increase in cost of natural gas and NGLs for Bison Midstream and Grand River.

• a partial year of operations for Tioga Midstream and Niobrara G&P, which commenced operations in September 2013.

• an increase in operation and maintenance expense as a result of the continued development of the Polar and Divide system.

• an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

Cost of Natural Gas and NGLs.The decrease in cost of natural gas and NGLs for the year ended December 31, 2015 was largely driven by declining commodity prices and the associated impact on our percent-of-proceeds arrangements at Bison Midstream and Grand River. The increase in cost of natural gas and NGLs for the year ended December 31, 2014 was primarily attributable to an increase in volume throughput, partially offset by declining commodity prices.

Operation and Maintenance. 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 a decline 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.)

Operation and maintenance expense increased during the year ended December 31, 2014 primarily as a result of the 2014 start up of Tioga Midstream, an environmental remediation accrual for assets contributed to Polar and Divide, a full year of operations for both Mountaineer Midstream and Polar and Divide as well as higher expenses at Bison Midstream, including an increase in pass-through electricity expense (revenue component is recognized in other revenues).

General and Administrative. General and administrative expense increased during the year ended December 31, 2015 reflecting a an increase in salaries, benefits and unit-based and noncash 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").

General and administrative expense increased during the year ended December 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily due to increased head count, an increase in professional expenses associated with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of COSO 2013 and rent expenses.

Transaction Costs. Transaction costs recognized primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down in 2015, the Red Rock Drop Down in 2014 and the Bison Drop Down and the acquisition of Mountaineer Midstream in 2013. Transaction costs also include financial and legal advisory expenses incurred by Summit Investments in 2015 and 2014 for third-party acquisitions that were allocated to us in connection with the 2016 Drop Down.

Depreciation and Amortization. The increase in depreciation and amortization expense during the years ended December 31, 2015 and 2014 was largely driven by an increase in assets placed into service and an increase in contract amortization largely due to Grand River.

EX 99.1-11

EXHIBIT 99.1

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

The increase in interest expense during the year ended December 31, 2014 was primarily driven by our June 2013 issuance of 7.5% senior notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

Segment Overview of the Years Ended December 31, 2015, 2014 and 2013

Utica Shale. Our ownership interests in Ohio Gathering are the primary component of the Utica Shale reportable segment. We acquired substantially all of Summit Investments' indirect ownership interest in Ohio Gathering, a natural gas gathering system and a condensate stabilization facility, in March 2016 (see the notes to the consolidated financial statements for additional information). The Utica Shale reportable segment also includes Summit Utica, a natural gas gathering system, which was acquired from a subsidiary of Summit Investments in March 2016. Our segment financial results include recognition of our proportional adjusted EBITDA activity for Ohio Gathering since January 2014, the date on which common control began.

Volume throughput for our Utica Shale reportable segment, exclusive of volume throughput data for Ohio Gathering which we do not operate, follows.

	Utica Shale (1)
	Year ended December 31,		Percentage Change
	2015	2014	2015 v. 2014
Operating Data:
Average throughput (MMcf/d) (2)	37	1	*

__________

(1) Summit Utica contract terms related to throughput rate per Mcf are excluded for confidentiality purposes.

(2) For the year ended December 31, 2014. For the period of SMLP's ownership in 2014, average throughput was 12 MMcf/d.

* Not considered meaningful

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Year ended December 31,				Percentage Change
	2015		2014		2015 v. 2014
	(In thousands)
Revenues:
Gathering services and related fees	$	4,700	$	190	*
Total revenues	4,700		190		*
Costs and expenses:
Operation and maintenance	1,017		—		*
General and administrative	1,477		20		*
Depreciation and amortization	1,417		—		*
Total costs and expenses	3,911		20		*
Add:
Proportional adjusted EBITDA for equity method investees	33,667		6,006
Depreciation and amortization	1,417		—
Segment adjusted EBITDA	$	35,873	$	6,176	*

__________

EX 99.1-12

EXHIBIT 99.1

* Not considered meaningful

Year ended December 31, 2015. Segment adjusted EBITDA increased $29.7 million during 2015 reflecting:

• an increase in Ohio Gathering's adjusted EBITDA due to ongoing growth and development.

• a full year of operations and the growth and development of Summit Utica.

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

Williston Basin. Bison Midstream, Polar and Divide and Tioga Midstream provide our services for the Williston Basin reportable segment. Bison Midstream, an associated natural gas gathering system, was acquired from a subsidiary of Summit Investments in June 2013. Polar and Divide, a crude oil and produced water gathering system and transmission pipelines, was acquired from subsidiaries of Summit Investments in May 2015. Tioga Midstream, an associated natural gas, crude oil and produced water gathering system, was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for all periods during which the assets were under common control. Common control began in February 2013 for Bison Midstream and Polar and Divide and in April 2014 for Tioga Midstream.

Operating data for our Williston Basin reportable segment follows.

	Williston Basin
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013
Operating Data:
Average throughput – natural gas (MMcf/d) (1)	23		18		14		28	%	29	%
Average throughput rate per Mcf – gas	$	2.40	$	3.44	$	3.86	(30	)%	(11	)%
Average throughput – liquids (Mbbl/d) (2)	67.7		40.7		10.9		66	%	*
Average throughput rate per Bbl – liquids	$	1.84	$	1.69	$	0.95	9	%	78	%

__________

* Not considered meaningful

(1) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 16 MMcf/d.

(2) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 12.5 Mbbl/d.

Natural gas. 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.

The increase in natural gas volume throughput in 2014 primarily reflects additional pad site connections and newly installed compression capacity on Bison Midstream, which improved system hydraulics.

The declines in natural gas gathering rates in 2015 and 2014 were primarily a result of the impact of declining commodity prices on volumes associated with a percent-of-proceeds contract.

Liquids. The increase in liquids volume throughput in 2015 and 2014 reflect new pad site connections and ongoing drilling activity in Polar and Divide's service area.

The increase in average throughput rate for liquids for 2015 and 2014 was primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

EX 99.1-13

EXHIBIT 99.1

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013
	(In thousands)
Revenues:
Gathering services and related fees	$	62,899	$	41,766	$	21,132	51	%	98	%
Natural gas, NGLs and condensate sales	23,525		56,040		47,130		(58	)%	19	%
Other revenues	12,505		12,001		13,239		4	%	(9	)%
Total revenues	98,929		109,807		81,501		(10	)%	35	%
Costs and expenses:
Cost of natural gas and NGLs	23,090		54,481		54,840		(58	)%	(1	)%
Operation and maintenance	26,586		22,926		8,849		16	%	159	%
General and administrative	5,400		8,474		4,402		(36	)%	93	%
Depreciation and amortization	31,376		24,027		16,669		31	%	44	%
Environmental remediation	21,800		5,000		—		*		*
(Gain) loss on asset sales, net	5		296		—		*		*
Long-lived asset impairment	7,554		—		—		*		*
Goodwill impairment	203,373		54,199		—		*		*
Total costs and expenses	319,184		169,403		84,760		88	%	100	%
Add:
Depreciation and amortization	31,376		24,027		16,669
Adjustments related to MVC shortfall payments	11,870		10,743		3,600
Unit-based compensation	85		340		340
Loss on asset sales	5		296		—
Long-lived asset impairment	7,554		—		—
Goodwill impairment	203,373		54,199		—
Segment adjusted EBITDA	$	34,008	$	30,009	$	17,350	13	%	73	%

__________

* Not considered meaningful

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

• an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

• the impact of higher volume throughput on gathering services and related fees as well as other revenues generated by the Polar and Divide system.

• higher gathering rates associated with amendments to liquids contracts in 2014.

• a decline in general and administrative expenses primarily as a result of our decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments beginning in the first quarter of 2015.

• the impact of declining commodity prices which negatively affect the margins we earn under percent-of-proceeds arrangements at Bison Midstream.

• an increase in operation and maintenance expense largely as a result of system buildout on the Polar and Divide and Tioga Midstream systems.

Depreciation and amortization increased during 2015 largely as a result of assets placed into service. During 2015, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment was impaired; as such, we recognized a long-lived asset impairment. The goodwill impairment

EX 99.1-14

EXHIBIT 99.1

recognized in 2015 relates to our determination that all of the goodwill associated with the Polar and Divide reporting unit had been impaired.

Year ended December 31, 2014. Segment adjusted EBITDA increased $12.7 million during 2014 reflecting:

• the impact of higher volume throughput on gathering services and related fees as well as other revenues generated by the Polar and Divide system.

• higher gathering rates associated with amendments to liquids contracts in 2014.

• increased volumes under our percent-of-proceeds arrangements on the Bison Midstream system.

• higher operating and maintenance expense to support volume growth across the systems.

• an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down

The increase in depreciation and amortization expense during 2014 was largely driven by an increase in assets placed into service and contract amortization. The goodwill impairment recognized in 2014 relates to our determination that all of the goodwill associated with the Bison Midstream reporting unit had been impaired.

For additional information, see the sections entitled "Non-GAAP Financial Measures—Non-GAAP reconciliations items to note," "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" herein and Notes 2 and 6 to the consolidated financial statements.

Piceance/DJ Basins. Grand River, a natural gas gathering and processing system, provides our midstream services for the Piceance/DJ Basins reportable segment. Red Rock Gathering became part of the Grand River system in connection with the Red Rock Drop Down in March 2014. As noted above, our results include activity for Red Rock Gathering since October 2012, the date on which common control began. Niobrara G&P, an associated natural gas gathering and processing system in the DJ Basin, was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for Niobrara G&P since February 2013, the date on which common control began. For additional information, see the notes to the consolidated financial statements.

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

	Piceance/DJ Basins
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013
Operating Data:
Average throughput (MMcf/d)	609		663		647		(8	)%	2	%
Average throughput rate per Mcf	$	0.57	$	0.51	$	0.41	12	%	24	%

Volume throughput during 2015 was favorably impacted by new pad site connections for WPX Energy, Inc. and Ursa Resources Group II as well as the March 2014 start-up of a cryogenic processing plant servicing production from Black Hills Corporation. Volume throughput on the Legacy Grand River system declined in 2014 primarily as a result of Encana's continued suspension of drilling activities, which began in the fourth quarter of 2013.

The aggregate average throughput rate increased during 2015 and 2014 largely as a result of a shift in volume throughput mix. Volume growth from Red Rock Gathering's anchor customers continues to offset volume declines on the Legacy Grand River system and thereby has translated into higher average gathering rates per Mcf.

EX 99.1-15

EXHIBIT 99.1

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

	Piceance/DJ Basins
	Year ended December 31,							Percentage Change
	2015			2014		2013		2015 v. 2014		2014 v. 2013
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	161,291		$	122,852	$	96,485	31	%	27	%
Natural gas, NGLs and condensate sales	11,854			27,606		23,865		(57	)%	16	%
Other revenues	7,273			11,019		9,397		(34	)%	17	%
Total revenues	180,418			161,477		129,747		12	%	24	%
Costs and expenses:
Cost of natural gas and NGLs	8,308			17,934		13,197		(54	)%	36	%
Operation and maintenance	36,674			37,945		35,025		(3	)%	8	%
General and administrative	3,624			10,029		14,233		(64	)%	(30	)%
Depreciation and amortization	47,433			42,959		36,185		10	%	19	%
(Gain) loss on asset sales	(190		)	146		—		*		*
Long-lived asset impairment	1,220			—		—		*		*
Goodwill impairment	45,478			—		—		*		*
Total costs and expenses	142,547			109,013		98,640		31	%	11	%
Other income	—			1,185		—		*		*
Add:
Depreciation and amortization	47,433			42,959		36,185
Adjustments related to MVC shortfall payments	(21,590		)	15,194		12,395
Loss on asset sales	24			146		—
Long-lived asset impairment	1,220			—		—
Goodwill impairment	45,478			—		—
Less:
Gain on asset sales	214			—		—
Impact of purchase price adjustment	—			1,185		—
Segment adjusted EBITDA	$	110,222		$	110,763	$	79,687	—	%	39	%

__________

* Not considered meaningful

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

• the impact of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts.

• lower gathering services revenue from our Grand River anchor customer, partially offset by the contribution from Niobrara G&P.

• the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.

• an increase in anticipated MVC shortfall payments due to increasing rate and volume commitment provisions in certain gas gathering agreements.

Gathering services and related fees also reflect the recognition of revenue that had been previously deferred in connection with an MVC arrangement, which was determined to no longer be recoverable by the customer. Because we exclude the impacts of adjustments related to MVC shortfall payments from our definition of segment adjusted EBITDA, this metric was not impacted by the 2015 deferred revenue release. (See Note 8 to the consolidated financial statements for additional information.) Other revenues and operation and maintenance also reflect the effect of a decrease in certain electricity expenses, which, due to their pass-through nature, have no

EX 99.1-16

EXHIBIT 99.1

impact on segment adjusted EBITDA. Depreciation and amortization increased during the year ended December 31, 2015 largely as a result of an increase in contract amortization for Grand River's anchor customer, the March 2014 commissioning of a cryogenic processing plant and the development of Niobrara G&P. During 2015, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment was impaired; as such, we recognized a long-lived asset impairment. The goodwill impairment recognized in 2015 relates to our determination that all of the goodwill associated with the Grand River reporting unit had been impaired.

Year ended December 31, 2014. Segment adjusted EBITDA increased $31.1 million during 2014 reflecting:

• higher gathering services and related fees, largely due to the proportionate contribution of higher margin volume throughput from certain customers, the contribution from Niobrara G&P and the first quarter 2014 commissioning of a natural gas processing plant.

• an increase in anticipated MVC shortfall payments due to increasing rate and volume commitment provisions in certain gas gathering agreements.

• a decline in operation and maintenance.

Other revenues and operation and maintenance also reflect the effect of a decrease in certain electricity expenses, which, due to their pass-through nature, have no impact on segment adjusted EBITDA. Depreciation and amortization increased during 2014 largely as a result an increase in contract amortization and assets placed into service on the Grand River system. Other income represents the write off of certain balances that had been previously recognized in connection with the purchase accounting for the Legacy Grand River system.

For additional information, see the sections entitled "Non-GAAP Financial Measures—Non-GAAP reconciliations items to note," "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" herein and Notes 2, 6 and 16 to the consolidated financial statements.

Barnett Shale. DFW Midstream, a natural gas gathering system, provides our midstream services for the Barnett Shale reportable segment. On September 30, 2014, DFW Midstream acquired certain natural gas gathering assets (the "Lonestar assets"). The Lonestar assets gather natural gas under two long-term, fee-based gathering agreements.

Operating data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013
Operating Data:
Average throughput (MMcf/d)	352		358		391		(2	)%	(8	)%
Average throughput rate per Mcf	$	0.62	$	0.59	$	0.59	5	%	—	%

Volume throughput was flat in 2015 after declining in 2014. The 2015 year-over-year comparison reflects 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 anchor customer.

For 2014, the decline in volume throughput reflected the impact of multiple customers temporarily shutting-in several large pad sites to drill or complete new wells as noted above. In addition, 2013 volume throughput benefited early in the year due to the first quarter 2013 commissioning of an additional compressor which increased throughput capacity on the DFW Midstream system by 40 MMcf/d.

The higher average throughput rate in 2015 is primarily the result of a shift in volume mix.

Our customers have a number of wells that have been drilled and are in various stages of the completion process; many of which we expect to begin producing before the third quarter of 2016. In addition, one of our customers recently moved a drilling rig back into our service area to drill new wells which we expect will stimulate volume throughput in the second half of 2016.

EX 99.1-17

EXHIBIT 99.1

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Year ended December 31,									Percentage Change
	2015			2014			2013			2015 v. 2014		2014 v. 2013
	(In thousands)
Revenues:
Gathering services and related fees	$	80,461		$	79,976		$	89,147		1	%	(10	)%
Natural gas, NGLs and condensate sales	6,700			13,448			17,190			(50	)%	(22	)%
Other revenues	881			(423		)	(1,013		)	*		*
Total revenues	88,042			93,001			105,324			(5	)%	(12	)%
Costs and expenses:
Operation and maintenance	25,823			29,438			31,784			(12	)%	(7	)%
General and administrative	1,297			4,607			6,129			(72	)%	(25	)%
Depreciation and amortization	15,606			15,657			13,929			—	%	12	%
Loss on asset sales	13			—			113			*		*
Long-lived asset impairment	531			5,505			—			*		*
Total costs and expenses	43,270			55,207			51,955			(22	)%	6	%
Add:
Depreciation and amortization	16,392			16,601			14,961
Adjustments related to MVC shortfall payments	(2,182		)	628			1,030
Loss on asset sales	13			—			113
Long-lived asset impairment	531			5,505			—
Segment adjusted EBITDA	$	59,526		$	60,528		$	69,473		(2	)%	(13	)%

__________

*Not considered meaningful

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

• the impact of declining natural gas prices on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets.

• lower electricity expense which is reflected in operation and maintenance. We purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices. As a result, the decline in natural gas prices translated into lower electricity expenses. This decline was partially offset by an increase in compression expense.

• the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.

Depreciation and amortization increased during 2015 largely as a result of placing the Lonestar assets into service in September 2014.

Year ended December 31, 2014. Segment adjusted EBITDA decreased $8.9 million during 2014 reflecting:

• the impact of declining natural gas prices on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets.

• a decrease in gathering services and related fees due to lower volumes.

Depreciation and amortization increased during 2014 largely as a result of placing the Lonestar assets into service in September 2014.

EX 99.1-18

EXHIBIT 99.1

Marcellus Shale. Mountaineer Midstream, a natural gas gathering system, provides our midstream services for the Marcellus Shale reportable segment. We acquired Mountaineer Midstream in June 2013. Volume throughput for the Marcellus Shale reportable segment follows.

	Marcellus Shale (1)
	Year ended December 31,			Percentage Change
	2015	2014	2013 (2)	2015 v. 2014		2014 v. 2013
Operating Data:
Average throughput (MMcf/d)	478	382	87	25	%	*

__________

* Not considered meaningful

(1) Contract terms related to throughput rate per MCF are excluded for confidentiality purposes.

(2) For the period of SMLP's ownership in 2013, average throughput was 164 MMcf/d.

The increase in volume throughput in 2015, compared to 2014, was primarily driven by the upstream connection of wells owned by Mountaineer Midstream's anchor customer, Antero.

The increase in volume throughput in 2014, compared with 2013, reflects the continuation of active drilling by Antero and the connection of new wells upstream of the Mountaineer Midstream system as well as the impact of new, upstream compressor stations commissioned by third parties, which contributed to volume throughput.

We expect volumes on the Mountaineer Midstream system to increase throughout the second and third quarters of 2016 as Antero completes a portion of its deferred well inventory.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013
	(In thousands)
Revenues:
Gathering services and related fees	$	28,468	$	22,694	$	9,588	25	%	137	%
Total revenues	28,468		22,694		9,588		25	%	137	%
Costs and expenses:
Operation and maintenance	4,886		4,560		2,447		7	%	86	%
General and administrative	368		2,194		808		(83	)%	*
Depreciation and amortization	8,682		7,648		3,998		14	%	91	%
Total costs and expenses	13,936		14,402		7,253		(3	)%	99	%
Add:
Depreciation and amortization	8,682		7,648		3,998
Segment adjusted EBITDA	$	23,214	$	15,940	$	6,333	46	%	*

__________

* Not considered meaningful

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

• the impact of an increase in volume throughput which translated into higher gathering services and related fees revenue.

• minimum revenue commitment payments related to the Zinnia Loop project, beginning in the first quarter of 2015.

• the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.

• an increase in operation and maintenance primarily as a result of system expansion and the associated increase in volume throughput.

EX 99.1-19

EXHIBIT 99.1

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

Year ended December 31, 2014. Segment adjusted EBITDA increased $9.6 million during 2014 reflecting:

• a full year of operations under SMLP's management as well as our build out of the Mountaineer Midstream system to keep pace with increases in production from Antero as processing capacity at MPLX’s Sherwood Processing Complex increased.

Depreciation and amortization increased during the year ended December 31, 2014 largely as a result of a full year of operations.

Corporate. Corporate 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 and interest expense. Items to note follow.

	Corporate
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013
	(In thousands)
Costs and expenses:
General and administrative	$	32,942	$	17,957	$	11,144	83	%	61	%
Transaction costs	1,342		2,985		2,841		(55	)%	5	%
Interest expense	59,092		48,586		21,314		22	%	128	%

General and Administrative. The increase in general and administrative expense during the year ended December 31, 2015, largely reflects the impact of our decision to discontinue allocating certain expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.

General and administrative expense increased during the year ended December 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily due to increased head count, an increase in professional expenses associated with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of COSO 2013.

Transaction Costs. Transaction costs recognized primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down in 2015, the Red Rock Drop Down in 2014 and the Bison Drop Down and the acquisition of Mountaineer Midstream in 2013. Transaction costs also include financial and legal advisory expenses incurred by Summit Investments in 2015 and 2014 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, 2015 was primarily driven by our July 2014 issuance of 5.5% senior notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

The increase in interest expense during the year ended December 31, 2014 was primarily driven by our June 2013 issuance of 7.5% senior notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

Non-GAAP Financial Measures

EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP.

• EBITDA. We define EBITDA as net income or loss, plus interest expense, income tax expense and depreciation and amortization, less interest income and income tax benefit.

• Adjusted EBITDA. We define adjusted EBITDA as EBITDA plus our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses, less income (loss) from equity method investees and other noncash income or gains.

EX 99.1-20

EXHIBIT 99.1

• Distributable Cash Flow. We define distributable cash flow as adjusted EBITDA plus cash interest received, less cash interest paid, senior notes interest adjustment, cash taxes paid and maintenance capital expenditures.

We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

Net income or loss and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of these limitations include:

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

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

• EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs;

• although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and

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

We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.

EBITDA, adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Non-GAAP reconciliations items to note. The following items should be noted when reviewing our non-GAAP reconciliations:

• Interest expense presented in the net income-basis non-GAAP reconciliation includes amortization of deferred loan costs while interest expense presented in the cash flow-basis non-GAAP reconciliation is adjusted to exclude amortization of deferred loan costs. See the consolidated statements of cash flows for additional information.

• Depreciation and amortization includes the favorable and unfavorable gas gathering contract amortization expense reported in other revenues.

• Proportional adjusted EBITDA for equity method investees accounts for our pro rata share of Ohio Gathering's adjusted EBITDA.

• Adjustments related to MVC shortfall payments 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. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment. See Notes 2 and 3 to the consolidated financial statements for additional information.

• Goodwill impairments recognized during 2015 and 2014 are discussed in the sections entitled "Results of Operations" and "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" as well as Note 6 to the consolidated financial statements.

• Long-lived asset impairments recognized during 2015 and 2014 are discussed in the sections entitled "Results of Operations" and "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" as well as Note 4 to the consolidated financial statements.

EX 99.1-21

EXHIBIT 99.1

• The impact of purchase price adjustment reflects certain balances previously recognized in connection with the Predecessor's purchase accounting for the Legacy Grand River system that we wrote off during the fourth quarter of 2014. This write off was recognized in other income. See "Results of Operations—Piceance/DJ Basins" and Note 16 to the consolidated financial statements for additional information.

• Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 9 to the consolidated financial statements for additional information.

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

• As a result of accounting for our drop down transactions similar to a pooling of interests, EBITDA, adjusted EBITDA, and distributable cash flow reflect the historical operations, financial position and cash flows of contributed subsidiaries for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 16 to the consolidated financial statements for additional information.

• EBITDA, adjusted EBITDA, distributable cash flow and net cash provided by operating activities include transaction costs. These unusual expenses are settled in cash. For additional information, see "Results of Operations—Corporate" herein.

EX 99.1-22

EXHIBIT 99.1

Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow:
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008
Add:
Interest expense	59,092			48,586			21,314
Income tax expense	—			854			729
Depreciation and amortization	105,903			91,822			72,264
Less:
Interest income	2			4			5
Income tax benefit	603			—			—
EBITDA	$	(57,838	)	$	93,890		$	141,310
Add:
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based and noncash compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
(Loss) from equity method investees	(6,563		)	(16,712		)	—
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Adjusted EBITDA	$	235,491		$	207,975		$	162,690
Add cash interest received	2			4			5
Less:
Cash interest paid	59,302			38,453			13,170
Senior notes interest adjustment	(1,421		)	6,733			12,125
Cash taxes paid	—			—			660
Maintenance capital expenditures	12,681			18,082			16,129
Distributable cash flow	$	164,931		$	144,711		$	120,611

EX 99.1-23

EXHIBIT 99.1

Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow:
Net cash provided by operating activities	$	191,375		$	152,953		$	135,411
Add:
(Loss) from equity method investees	(6,563		)	(16,712		)	—
Interest expense, excluding deferred loan costs	54,783			44,750			18,557
Income tax expense	—			854			729
Impact of purchase price adjustment	—			1,185			—
Changes in operating assets and liabilities	3,541			(18,603		)	(9,027		)
Gain on asset sales	214			—			—
Less:
Unit-based compensation	7,017			5,841			4,242
Distributions from equity method investees	34,641			2,992			—
Interest income	2			4			5
Income tax benefit	603			—			—
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Write-off of debt issuance costs	727			1,554			—
EBITDA	$	(57,838	)	$	93,890		$	141,310
Add:
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
(Loss) from equity method investees	(6,563		)	(16,712		)	—
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Adjusted EBITDA	$	235,491		$	207,975		$	162,690
Add cash interest received	2			4			5
Less:
Cash interest paid	59,302			38,453			13,170
Senior notes interest adjustment	(1,421		)	6,733			12,125
Cash taxes paid	—			—			660
Maintenance capital expenditures	12,681			18,082			16,129
Distributable cash flow	$	164,931		$	144,711		$	120,611

EX 99.1-24

EXHIBIT 99.1

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 flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt instruments.

Capital Markets Activity

November 2013 Shelf Registration Statement. In October 2013, we filed a shelf registration statement with the SEC to register up to $1.2 billion of equity and debt securities in primary offerings as well as all of the 14,691,397 common units held by a subsidiary of Summit Investments in accordance with our obligations under several registration rights agreements. In November 2013, the SEC declared our shelf registration statement effective.

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. Concurrent with the offering, our general partner made a capital contribution to maintain its 2% general partner interest. We used the proceeds from our primary offering of common units and the general partner capital contribution to fund a portion of the purchase of Red Rock Gathering.

In September 2014, a subsidiary of Summit Investments completed an underwritten public offering of 4,347,826 SMLP common units. We did not receive any proceeds from this offering.

On May 13, 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 2% general partner interest. We used the proceeds from the May 13, 2015 transaction to partially fund the Polar and Divide Drop Down. We used $25.0 million of the $29.0 million proceeds from the exercise of the underwriters' option to pay down our revolving credit facility. Following the May 2015 Equity Offering and the exercise of the underwriters' option, we can issue up to $464.8 million of debt and equity securities in primary offerings and 5,293,571 common units pursuant to this shelf registration statement.

In June 2015, we executed an equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the "June 2015 ATM Program"). These sales will be made (i) pursuant to the terms of the equity distribution agreement between us and the sales agents named therein and (ii) by means of ordinary brokers' transactions at market prices, in block transactions or as otherwise agreed between us and the sales agents. Sales of our common units may be made in negotiated transactions or transactions that are deemed to be "at-the-market offerings" as defined by SEC Rules. There were no transactions under the June 2015 ATM Program during the period from inception to December 31, 2015.

July 2014 Shelf Registration Statement. In July 2014, we filed a registration statement 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 notes due 2022. We used the proceeds to repay a portion of the outstanding borrowings under our revolving credit facility.

Private Offerings of Debt and Equity. In June 2013, we issued $300.0 million unregistered 7.5% senior unsecured notes and guarantees notes maturing July 1, 2021 (the "7.5% senior notes") and used the net proceeds to partially fund the acquisition of Mountaineer Midstream. In March 2014, the SEC declared our registration statement to exchange all of the unregistered 7.5% senior notes and guarantees for registered senior notes and guarantees with substantially identical terms effective. In April 2014, the exchange period concluded with 100% of the unregistered senior notes being exchanged for registered notes.

In June 2013, we issued common limited partner units and general partner interests to a subsidiary of Summit Investments to partially fund the Bison Drop Down and the acquisition of Mountaineer Midstream.

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

Debt

Revolving Credit Facility. As of December 31, 2015, we had a $700.0 million senior secured revolving credit facility. As of December 31, 2015, the outstanding balance of the revolving credit facility was $344.0 million and the unused portion totaled $356.0 million. There were no defaults or events of default during 2015 and, as of December 31, 2015, we were in compliance with the covenants in the revolving credit facility.

EX 99.1-25

EXHIBIT 99.1

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes"). The 7.5% senior notes were initially sold in reliance on Rule 144A and 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 7.5% senior notes and the guarantees of those notes for identical registered notes and guarantees. There were no defaults or events of default during 2014 on either series of senior notes.

SMP Holdings Credit Facility. SMP Holdings had a senior secured revolving credit facility (the "SMP Revolving Credit Facility") and a senior secured term loan (the "Term Loan" and, collectively with the SMP Revolving Credit Facility, the "SMP Holdings Credit Facility") which were used to support the development of the 2016 Drop Down Assets. Borrowings under the SMP Holdings Credit Facility incurred interest at LIBOR or a base rate (as defined in the SMP Holdings Credit Facility) plus an applicable margin. Because the funding was used to support the development of the 2016 Drop Down Assets, Summit Investments allocated the SMP Holdings Credit Facility to us during the years ended December 31, 2015, 2014 and 2013.

On March 3, 2016, the outstanding balances on the SMP Holdings Credit Facility were repaid in full and the SMP Holdings Credit Facility was terminated concurrent with the closing of the 2016 Drop Down (see Note 16).

For additional information on our long-term debt and debt allocated to us, see Notes 9 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 a liability for a deferred purchase price obligation. For additional information on the deferred purchase price obligation, see Note 16 to the unaudited condensed consolidated financial statements.

Cash Flows

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

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Net cash provided by operating activities	$	191,375		$	152,953		$	135,411
Net cash used in investing activities	(646,720		)	(1,384,803		)	(659,041		)
Net cash provided by financing activities	449,327			1,233,877			538,080
Net change in cash and cash equivalents	$	(6,018	)	$	2,027		$	14,450

Operating activities. Cash flows from operating activities increased by $38.4 million for the year ended December 31, 2015 primarily due to distributions from Ohio Gathering and cash received as a result of MVCs. The impact of these cash receipts was largely offset by an increase in interest due to the 5.5% senior notes and other operating activities.

Cash flows from operating activities increased by $17.5 million for the year ended December 31, 2014 largely due to cash received as a result of MVCs.

Investing activities. Cash flows used in investing activities for the year ended December 31, 2015 were related primarily to: (i) the Polar and Divide Drop Down, (ii) the ongoing expansion of compression capacity on the Bison Midstream system, (iii) ongoing expansion of the Summit Utica, Tioga Midstream, Niobrara G&P and Polar and Divide systems, including the Stampede Lateral and (iv) pipeline construction projects to connect new receipt points on the Grand River and Bison Midstream systems.

Cash flows used in investing activities for the year ended December 31, 2014 primarily reflect Summit Investments' investment in Ohio Gathering, the Partnership's acquisition of Red Rock Gathering from a subsidiary of Summit Investments and build out of the Summit Utica, Tioga Midstream, Niobrara G&P and Polar and Divide systems. Additional expenditures for the year ended December 31, 2014 primarily reflect construction of a processing plant on the Grand River system, projects to expand compression capacity on the Bison Midstream system, adding

EX 99.1-26

EXHIBIT 99.1

pipeline on the Mountaineer Midstream system, the February 2014 commissioning of a new natural gas treating facility on the DFW Midstream system and the purchase of the Lonestar assets.

Cash flows used in investing activities for the year ended December 31, 2013 were largely due to the acquisitions of Bison Midstream and Mountaineer Midstream and construction of the Polar and Divide and Niobrara G&P systems. Additional expenditures in 2013 reflect the construction of seven miles of new gathering pipeline across the DFW Midstream system and the acquisition of previously leased compression assets on the Grand River system. We also commissioned a new compressor unit on the DFW Midstream system in January 2013. Development activities also included construction projects to connect new receipt points on the Bison Midstream and DFW Midstream systems and to expand compression capacity on the Bison Midstream system. We also began construction on a new 150 gallon per minute natural gas treating facility on the DFW Midstream system, which was commissioned in the first quarter of 2014.

Financing activities. Details of cash flows provided by financing activities were as follows:

Net cash used in financing activities for the year ended December 31, 2015 was primarily composed of the following:

• Net proceeds from an offering of common units in May 2015, which were used to partially fund the Polar and Divide Drop Down;

• Cash advances to support the buildout of the systems acquired in the 2016 Drop Down;

• Net borrowings under our revolving credit facility, including $92.5 million to partially fund the Polar and Divide Drop Down; and

• Distributions declared and paid in 2015.

Net cash provided by financing activities for the year ended December 31, 2014 was primarily composed of the following:

• Cash advances to fund the acquisition of Ohio Gathering and to support the buildout of the systems acquired in the 2016 Drop Down;

• Proceeds from the 5.5% senior notes issuance, the net of which was used to pay down our revolving credit facility. We incurred loan costs of $5.1 million in connection with their issuance which will be amortized over the life of the notes;

• Borrowings of $100.0 million under our revolving credit facility to partially fund the Red Rock Drop Down;

• Net proceeds from an offering of common units in March 2014, which were used to partially fund the Red Rock Drop Down;

• Distributions declared and paid in 2014; and

• Cash advances to support the buildout of the Polar and Divide system.

Net cash provided by financing activities for the year ended December 31, 2013 was primarily composed of the following:

• Distributions declared and paid in 2013;

• Borrowings under our revolving credit facility, of which $200.0 million was used to partially fund the Bison Drop Down and $110.0 million was used to partially fund the Mountaineer Acquisition;

• Proceeds from the 7.5% senior notes issuance, the net of which was used to pay down our revolving credit facility. We incurred loan costs of $7.4 million in connection with the senior notes issuance which will be amortized over the life of the notes;

• Payments of $297.2 million on our revolving credit facility, $294.2 million of which was funded by the 7.5% senior notes issuance;

• Issuance of $98.0 million of common units and $2.0 million of general partner interests to Summit Investments for cash to partially fund the Mountaineer Acquisition; and

• Cash advances to support the buildout of the Polar and Divide system as well as the systems acquired in the 2016 Drop Down.

EX 99.1-27

EXHIBIT 99.1

Contractual Obligations

The table below summarizes our contractual obligations as of December 31, 2015.

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt and interest payments (1)	$	1,229,089	$	50,859	$	444,730	$	78,000	$	655,500
Purchase obligations (2)	33,672		32,384		1,188		100		—
Total contractual obligations	$	1,262,761	$	83,243	$	445,918	$	78,100	$	655,500

__________

(1) For the purpose of calculating future interest on the revolving credit facility, assumes no change in balance or rate from December 31, 2015. Includes a 0.50% commitment fee on the unused portion of the revolving credit facility. See Note 9 to the consolidated financial statements for additional information.

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

Operating leases. A substantial majority of the operating leases that support our operations have been entered into by Summit Investments with the associated rent expense allocated to us. Future minimum lease payments associated with operating leases in the Partnership's name are immaterial. See Note 15 to the consolidated financial statements for additional information.

Subsequent events. In March 2016, we borrowed an additional $360.0 million under our revolving credit facility and recognized a liability of $507.4 million for the deferred purchase price obligation, both in connection with the 2016 Drop Down (see Notes 9 and 16 to the consolidated financial statements for additional information). Additional interest expense on the incremental revolving credit facility borrowings will total $8.7 million on an annualized basis with maturity in November 2018, assuming no change in the balance, rate or commitment fee from December 31, 2015. The deferred purchase price obligation is due no later than December 31, 2020 and is currently expected to be $860.3 million based on information available as of March 31, 2016. There are no cash interest payments associated with the deferred purchase price obligation.

Capital Requirements

The table below summarizes our capital expenditures by reportable segment and in total for the years ended December 31.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Capital expenditures:
Utica Shale	$	94,994	$	24,787	$	—
Williston Basin	147,477		227,283		129,236
Piceance/DJ Basins	21,144		42,417		88,104
Barnett Shale	6,875		14,567		29,534
Marcellus Shale	1,306		33,866		1,822
Total reportable segment capital expenditures	271,796		342,920		248,696
Corporate	429		460		930
Total capital expenditures	$	272,225	$	343,380	$	249,626

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

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

EX 99.1-28

EXHIBIT 99.1

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

For the year ended December 31, 2015, SMLP recorded total capital expenditures of $272.2 million, which included $12.7 million of maintenance capital expenditures.

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

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 acquisition strategy 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 estimate the quarterly impact of expected MVC shortfall payments for inclusion in our calculation of adjusted EBITDA. As such, 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. The components of adjustments related to MVC shortfall payments by reportable segment for the year endedDecember 31, 2015 follow.

	Williston Basin		Piceance/DJ Basins			Barnett Shale			Total
	(In thousands)
Adjustments related to MVC shortfall payments:
Net change in deferred revenue for MVC shortfall payments (1)	$	11,870	$	(21,623	)	$	(1,700	)	$	(11,453	)
Expected MVC shortfall payments (2)	—		33			(482		)	(449		)
Total adjustments related to MVC shortfall payments	$	11,870	$	(21,590	)	$	(2,182	)	$	(11,902	)

__________

(1) See Notes 3 and 8 for additional information on the changes in deferred revenue.

(2) As of December 31, 2015, accounts receivable included $40.2 million of total shortfall payment billings, of which $12.7 million related to shortfall billings associated with MVC arrangements that can be utilized to offset gathering fees in future periods.

For additional information, see Notes 2, 3, 8 and 10 to the consolidated financial statements.

EX 99.1-29

EXHIBIT 99.1

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the year endedDecember 31, 2015.

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the Financial Accounting Standards Board. 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, our amortizing intangible assets and goodwill.

Property, Plant and Equipment and Amortizing Intangible Assets. As of December 31, 2015, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net amortizing intangible assets with a carrying value of approximately $461.3 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, including those recognized in 2015 and 2014 are disclosed in Note 4 to the consolidated financial statements, 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.

2014 Impairment Evaluations. We performed our 2014 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

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. See Notes 2 and 6 for additional information.

2015 Impairment Evaluations. We performed our 2015 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

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

EX 99.1-30

EXHIBIT 99.1

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 impairment as of December 31, 2014. See Notes 2 and 6 for additional information.

Minimum Volume Commitments

Certain of our gas gathering agreements provide for a monthly, quarterly or annual MVC from our customers. As of December 31, 2015, we had MVCs totaling 1.2 Bcfe/d through 2020.

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 $58.2 million of MVC shortfall payments to customers that did not meet their MVCs during 2015. 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 $39.5 million of gathering revenue due to the credit bank expiration of previous MVC shortfall payments. Of the gathering revenue, $37.1 million is related to the deferred revenue recognition associated with a certain Piceance/DJ Basins customer for which we determined that it would be remote that it could ship volumes in excess of its future MVC as an offset to future gathering fees. As such, the deferred revenue associated with this customer, as reflected on the balance sheet, was recognized as revenue on the income statement.

MVC shortfall payment adjustments in 2015 totaled $(0.4) million and included adjustments related to future anticipated shortfall payments from certain customers in the Piceance/DJ Basins, Williston Basin and Barnett Shale segments. The net impact of our MVC shortfall payment mechanisms increased adjusted EBITDA by $57.7 million in 2015.

EX 99.1-31

EXHIBIT 99.1

The following table presents the impact of our MVC activity by reportable segment during the year ended December 31, 2015.

	Year ended December 31, 2015
	MVC billings		Gathering revenue		Adjustments to MVC shortfall payments			Net impact to adjusted EBITDA
	(In thousands)
Net change in deferred revenue:
Williston Basin	$	11,897	$	27	$	11,870		$	11,897
Piceance/DJ Basins	15,508		37,131		(21,623		)	15,508
Barnett Shale	677		2,377		(1,700		)	677
Total change in deferred revenue	$	28,082	$	39,535	$	(11,453	)	$	28,082
MVC shortfall payment adjustments:
Piceance/DJ Basins	$	25,704	$	25,704	$	33		$	25,737
Barnett Shale	1,142		1,142		(482		)	660
Marcellus Shale	3,237		3,237		—			3,237
Total MVC shortfall payment adjustments	$	30,083	$	30,083	$	(449	)	$	29,634
Total	$	58,165	$	69,618	$	(11,902	)	$	57,716

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 natural gas 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, 2015, current deferred revenue totaled $0.7 million. Noncurrent deferred revenue totaled $45.5 million at December 31, 2015 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. Adjustments related to MVC shortfall payments account for:

• the net increases or decreases in deferred revenue for MVC shortfall payments and

• our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected MVC shortfall payments in our calculation of segment adjusted EBITDA each quarter prior to the quarter in which we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our consolidated financial statements.

We estimate expected annual 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.

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.

EX 99.1-32

EXHIBIT 99.1

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 external 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:

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

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

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

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

• actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;

• our ability to acquire any assets owned by third parties, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets, and our ability to obtain financing on acceptable terms from the credit and/or capital markets or other sources;

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

• the ability to attract and retain key management personnel;

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

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

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

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

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

• operational risks and hazards inherent in the gathering, treating and/or processing of natural gas, crude oil and produced water;

• weather conditions and seasonal trends;

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

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

EX 99.1-33

EXHIBIT 99.1

• the effects of litigation;

• changes in general economic conditions; and

• certain factors discussed elsewhere in this report.

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 99.1-34

EX-99.2

EXHIBIT 99.2

Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm	EX 99.2-2
Consolidated Balance Sheets as of December 31, 2015 and 2014	EX 99.2-3
Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013	EX 99.2-4
Consolidated Statements of Partners' Capital for the years ended December 31, 2015, 2014 and 2013	EX 99.2-5
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	EX 99.2-8
Notes to Consolidated Financial Statements	EX 99.2-10
1. Organization, Business Operations and Presentation and Consolidation	EX 99.2-10
2. Summary of Significant Accounting Policies	EX 99.2-12
3. Segment Information	EX 99.2-18
4. Property, Plant and Equipment, Net	EX 99.2-22
5. Amortizing Intangible Assets and Unfavorable Gas Gathering Contract	EX 99.2-23
6. Goodwill	EX 99.2-24
7. Equity Method Investments	EX 99.2-26
8. Deferred Revenue	EX 99.2-27
9. Debt	EX 99.2-29
10. Financial Instruments	EX 99.2-33
11. Partners' Capital	EX 99.2-34
12. Earnings Per Unit	EX 99.2-38
13. Unit-Based and Noncash Compensation	EX 99.2-39
14. Related-Party Transactions	EX 99.2-40
15. Commitments and Contingencies	EX 99.2-41
16. Acquisitions and Drop Down Transactions	EX 99.2-42
17. Condensed Consolidated Financial Information	EX 99.2-47
18. Unaudited Quarterly Financial Data	EX 99.2-59

EX 99.2-1

EXHIBIT 99.2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Summit Midstream GP, LLC and 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, 2015 and 2014, and the related consolidated statements of operations, partners' capital and membership interests, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Summit Midstream Partners, LP and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

The consolidated financial statements give retrospective effect to the Partnership's acquisition of Summit Midstream Utica, LLC, Meadowlark Midstream Company, LLC, Tioga Midstream, LLC, and the 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. from Summit Midstream Partners Holdings, LLC, (collectively the "2016 Drop Down") as a combination of entities under common control, which has been accounted for in a manner similar to a pooling of interests, as described in Notes 1 and 16 to the consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Atlanta, Georgia

February 26, 2016 (June 6, 2016 as to the effects of the 2016 Drop Down as described in Notes 1 and 16, and the retrospective application of the change in accounting policy for presentation of debt issuance costs as described in Note 1; September 1, 2016 as to the addition of disclosures in Note 17 required under Regulation S-X Rule 3-10 as a result of the 2016 Drop Down, and the change in the guarantor structure of the Senior Notes described in Note 9)

EX 99.2-2

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2015		2014
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	21,793	$	27,811
Accounts receivable	89,581		92,908
Insurance receivable	—		25,000
Other current assets	3,573		3,600
Total current assets	114,947		149,319
Property, plant and equipment, net	1,812,783		1,622,640
Intangible assets, net	461,310		489,282
Goodwill	16,211		265,062
Investment in equity method investees	751,168		706,172
Other noncurrent assets	8,253		9,987
Total assets	$	3,164,672	$	3,242,462
Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	40,808	$	38,391
Due to affiliate	1,149		2,711
Deferred revenue	677		2,377
Ad valorem taxes payable	10,271		9,179
Accrued interest	17,483		18,858
Accrued environmental remediation	7,900		25,000
Other current liabilities	13,297		15,307
Total current liabilities	91,585		111,823
Long-term debt	1,267,270		1,232,207
Deferred revenue	45,486		55,239
Noncurrent accrued environmental remediation	5,764		5,000
Other noncurrent liabilities	7,268		7,515
Total liabilities	1,417,373		1,411,784
Commitments and contingencies (Note 15)
Common limited partner capital (42,063 units issued and outstanding at December 31, 2015 and 34,427 units issued and outstanding at December 31, 2014)	744,977		649,060
Subordinated limited partner capital (24,410 units issued and outstanding at December 31, 2015 and 2014)	213,631		293,153
General partner interests (1,355 units issued and outstanding at December 31, 2015 and 1,201 units issued and outstanding at December 31, 2014)	25,634		24,676
Summit Investments' equity in contributed subsidiaries	763,057		863,789
Total partners' capital	1,747,299		1,830,678
Total liabilities and partners' capital	$	3,164,672	$	3,242,462

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

EX 99.2-3

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
	2015			2014			2013
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	337,819		$	267,478		$	216,352
Natural gas, NGLs and condensate sales	42,079			97,094			88,185
Other revenues	20,659			22,597			21,623
Total revenues	400,557			387,169			326,160
Costs and expenses:
Cost of natural gas and NGLs	31,398			72,415			68,037
Operation and maintenance	94,986			94,869			78,175
General and administrative	45,108			43,281			36,716
Transaction costs	1,342			2,985			2,841
Depreciation and amortization	105,117			90,878			71,232
Environmental remediation	21,800			5,000			—
(Gain) loss on asset sales, net	(172		)	442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Total costs and expenses	557,735			369,574			257,114
Other income	2			1,189			5
Interest expense	(59,092		)	(48,586		)	(21,314		)
(Loss) income before income taxes	(216,268		)	(29,802		)	47,737
Income tax benefit (expense)	603			(854		)	(729		)
Loss from equity method investees	(6,563		)	(16,712		)	—
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008
Less net income attributable to Summit Investments	(30,016		)	(23,376		)	3,424
Net (loss) income attributable to SMLP	(192,212		)	(23,992		)	43,584
Less net (loss) income attributable to general partner, including IDRs	3,398			3,125			1,035
Net (loss) income attributable to limited partners	$	(195,610	)	$	(27,117	)	$	42,549
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.20	)	$	(0.49	)	$	0.86
Common unit – diluted	$	(3.20	)	$	(0.49	)	$	0.86
Subordinated unit – basic and diluted	$	(2.88	)	$	(0.44	)	$	0.79
Weighted-average limited partner units outstanding:
Common units – basic	39,217			33,311			26,951
Common units – diluted	39,217			33,311			27,101
Subordinated units – basic and diluted	24,410			24,410			24,410

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

EX 99.2-4

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated									Total
	(In thousands)
Partners' capital, January 1, 2013	$	418,856		$	380,169		$	20,222		$	209,108		$	1,028,355
Net income	22,311			20,238			1,035			3,424			47,008
Distributions to unitholders	(46,286		)	(42,107		)	(1,803		)	—			(90,196		)
Unit-based compensation	2,999			—			—			—			2,999
Consolidation of Bison Midstream net assets	—			—			—			303,168			303,168
Contribution from Summit Investments to Bison Midstream	—			—			—			2,229			2,229
Purchase of Bison Midstream	47,936			—			978			(248,914		)	(200,000		)
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	28,558			26,846			1,131			(56,535		)	—
Issuance of units in connection with the Mountaineer Acquisition	98,000			—			2,000			—			100,000
Consolidation of Polar Midstream net assets	—			—			—			216,105			216,105
Consolidation of 2016 Drop Down net assets	—			—			—			21,968			21,968
Class B membership interest noncash compensation	17			—			—			1,226			1,243
Repurchase of DFW Net Profits Interests	(5,859		)	(5,859		)	(239		)	—			(11,957		)
Cash advance to Summit Investments from contributed subsidiaries, net	—			—			—			(50,087		)	(50,087		)
Capitalized interest allocated to contributed subsidiaries from Summit Investments	—			—			—			2,539			2,539
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			22,380			22,380
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			52			52
Partners' capital, December 31, 2013	$	566,532		$	379,287		$	23,324		$	426,663		$	1,395,806

EX 99.2-5

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)

	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated									Total
	(In thousands)
Partners' capital, December 31, 2013	$	566,532		$	379,287		$	23,324		$	426,663		$	1,395,806
Net (loss) income	(15,948		)	(11,169		)	3,125			(23,376		)	(47,368		)
Distributions to unitholders	(67,658		)	(49,796		)	(4,770		)	—			(122,224		)
Unit-based compensation	4,696			—			—			—			4,696
Tax withholdings on vested SMLP LTIP awards	(656		)	—			—			—			(656		)
Issuance of common units, net of offering costs	197,806			—			—			—			197,806
Contribution from general partner	—			—			4,235			—			4,235
Purchase of Red Rock Gathering	—			—			—			(307,941		)	(307,941		)
Excess of purchase price over acquired carrying value of Red Rock Gathering	(37,910		)	(26,891		)	(1,323		)	66,124			—
Assets contributed to Red Rock Gathering from Summit Investments	2,426			1,722			85			—			4,233
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			674,383			674,383
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			24,884			24,884
Capitalized interest allocated to contributed subsidiaries from Summit Investments	—			—			—			1,310			1,310
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			597			597
Class B membership interest noncash compensation	—			—			—			1,145			1,145
Repurchase of SMLP LTIP units	(228		)	—			—			—			(228		)
Partners' capital, December 31, 2014	$	649,060		$	293,153		$	24,676		$	863,789		$	1,830,678

EX 99.2-6

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)

	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated									Total
	(In thousands)
Partners' capital, December 31, 2014	$	649,060		$	293,153		$	24,676		$	863,789		$	1,830,678
Net (loss) income	(123,817		)	(71,793		)	3,398			(30,016		)	(222,228		)
Distributions to unitholders	(86,880		)	(55,410		)	(9,784		)	—			(152,074		)
Unit-based compensation	6,174			—			—			—			6,174
Tax withholdings on vested SMLP LTIP awards	(1,616		)	—			—			—			(1,616		)
Issuance of common units, net of offering costs	221,977			—			—			—			221,977
Contribution from general partner	—			—			4,737			—			4,737
Purchase of Polar and Divide	—			—			—			(285,677		)	(285,677		)
Excess of acquired carrying value over consideration paid for Polar and Divide	80,079			47,681			2,607			(130,367		)	—
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			320,527			320,527
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			22,879			22,879
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			1,079			1,079
Class B membership interest noncash compensation	—			—			—			843			843
Partners' capital, December 31, 2015	$	744,977		$	213,631		$	25,634		$	763,057		$	1,747,299

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

EX 99.2-7

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	105,903			91,822			72,264
Amortization of deferred loan costs	4,309			3,836			2,757
Unit-based and noncash compensation	7,017			5,841			4,242
Loss from equity method investees	6,563			16,712			—
Distributions from equity method investees	34,641			2,992			—
(Gain) loss on asset sales, net	(172		)	442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Write-off of debt issuance costs	727			1,554			—
Purchase accounting adjustment	—			(1,185		)	—
Changes in operating assets and liabilities:
Accounts receivable	3,328			(21,503		)	(21,950		)
Insurance receivable	25,000			(25,000		)	—
Trade accounts payable	(1,450		)	(420		)	(6,153		)
Due to affiliate	1,377			(883		)	1,427
Change in deferred revenue	(11,453		)	26,378			16,685
Ad valorem taxes payable	1,092			804			(11		)
Accrued interest	(1,375		)	6,714			12,128
Accrued environmental remediation, net	(16,336		)	30,000			—
Other, net	(3,724		)	2,513			6,901
Net cash provided by operating activities	191,375			152,953			135,411
Cash flows from investing activities:
Capital expenditures	(272,225		)	(343,380		)	(249,626		)
Initial contribution to Ohio Gathering	—			(8,360		)	—
Acquisition of Ohio Gathering Option	—			(190,000		)	—
Option Exercise	—			(382,385		)	—
Contributions to equity method investees	(86,200		)	(145,131		)	—
Proceeds from asset sales	323			325			585
Acquisition of gathering systems	—			(10,872		)	(210,000		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618		)	(305,000		)	(200,000		)
Net cash used in investing activities	(646,720		)	(1,384,803		)	(659,041		)

EX 99.2-8

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(152,074		)	(122,224		)	(90,196		)
Borrowings under revolving credit facility	367,000			294,295			476,950
Repayments under revolving credit facility	(151,000		)	(430,295		)	(297,180		)
Borrowings under term loan	—			400,000			200,000
Repayments under term loan	(182,500		)	(100,000		)	(100,000		)
Deferred loan costs	(412		)	(8,323		)	(14,059		)
Proceeds from issuance of common units, net	221,977			197,806			—
Contribution from general partner	4,737			4,235			2,229
Cash advance from (to) Summit Investments to (from) contributed subsidiaries, net	320,527			674,383			(50,087		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	22,879			24,884			22,380
Issuance of senior notes	—			300,000			300,000
Repurchase of equity-based compensation awards	—			(228		)	(11,957		)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	—			—			100,000
Other, net	(1,807		)	(656		)	—
Net cash provided by financing activities	449,327			1,233,877			538,080
Net change in cash and cash equivalents	(6,018		)	2,027			14,450
Cash and cash equivalents, beginning of period	27,811			25,784			11,334
Cash and cash equivalents, end of period	$	21,793		$	27,811		$	25,784
Supplemental cash flow disclosures:
Cash interest paid	$	59,302		$	38,453		$	13,170
Less capitalized interest	3,372			4,646			6,690
Interest paid (net of capitalized interest)	$	55,930		$	33,807		$	6,480
Cash paid for taxes	$	—		$	—		$	660
Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	34,977		$	31,110		$	30,528
Excess of acquired carrying value over consideration paid for Polar and Divide	130,367			—			—
Capitalized interest allocated to contributed subsidiaries from Summit Investments	1,079			1,310			2,539
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	—			597			52
Excess of consideration paid over acquired carrying value of Red Rock Gathering	—			(66,124		)	—
Assets contributed to Red Rock Gathering from Summit Investments	—			4,233			—
Issuance of units to affiliate to partially fund the Bison Drop Down	—			—			48,914
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	—			—			56,535

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

EX 99.2-9

EXHIBIT 99.2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, was formed in May 2012 and began operations in October 2012 in connection with its initial public offering ("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 Midstream Holdings, LLC ("Summit Holdings"), a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

Summit Midstream GP, LLC (the "general partner"), a Delaware limited liability company, manages our operations and activities. Summit Midstream Partners, LLC ("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 II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners").

In addition to its 2% general partner interest in SMLP (including the incentive distribution rights ("IDRs") in respect of SMLP), Summit Investments has direct and indirect ownership interests in our common and subordinated units. As of December 31, 2015, Summit Investments beneficially owned 5,444,731 SMLP common units and all of our subordinated 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 Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River" or the "Legacy Grand River" system).

On June 4, 2013, the Partnership acquired all of the membership interests of Bison Midstream, LLC ("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. Prior to the Bison Drop Down, on February 15, 2013, Summit Investments acquired Bear Tracker Energy, LLC ("BTE"), which was subsequently renamed Meadowlark Midstream Company, LLC ("Meadowlark Midstream"). 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.

On June 21, 2013, Mountaineer Midstream Company, LLC ("Mountaineer Midstream"), 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. ("MarkWest") (the "Mountaineer Acquisition"). In December 2013, Mountaineer Midstream was merged into DFW Midstream.

On March 18, 2014, SMLP acquired all of the membership interests of Red Rock Gathering Company, LLC ("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.

On May 18, 2015, the Partnership acquired all of the membership interests of Polar Midstream, LLC ("Polar Midstream") and Epping Transmission Company, LLC ("Epping," and collectively with Polar Midstream, "Polar and Divide") 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.

On February 25, 2016, the Partnership and Summit Midstream Partners Holdings, LLC (“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

EX 99.2-10

EXHIBIT 99.2

interest in Summit Midstream OpCo, LP ("OpCo"), a Delaware limited partnership that owns (i) 100% of the issued and outstanding membership interests of Summit Midstream Utica, LLC ("Summit Utica"), Meadowlark Midstream Company, LLC ("Meadowlark Midstream") and Tioga Midstream, LLC ("Tioga Midstream" and collectively with Summit Utica and Meadowlark Midstream, the "Contributed Entities"), each a limited liability company and (ii) a 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively with OpCo and the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down closed on March 3, 2016. Subsequent to closing, SMP Holdings retained a 1.0% noncontrolling interest in OpCo, which is managed by Summit Midstream OpCo GP, LLC ("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. Our gathering systems and the unconventional resource basins in which they operate are as follows:

• Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

• Bison Midstream, an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Polar and Divide, crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Tioga Midstream, crude oil, produced water and associated natural gas gathering systems, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Grand River, a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah;

• Niobrara Gathering and Processing ("Niobrara G&P"), an associated natural gas gathering and processing system operating in the Denver-Julesburg ("DJ") Basin, which includes the Niobrara shale formation in northeastern Colorado;

• DFW Midstream, a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

• Mountaineer Midstream gathering system ("Mountaineer Midstream"), a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

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.

Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively, "Ohio Gathering") operate a natural gas gathering system and a condensate stabilization facility in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio.

Presentation and Consolidation. We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board (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.

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) DFW Midstream and Grand River for all periods presented, (ii) Bison Midstream, Polar and Divide and Niobrara G&P since February 2013, (iii) Mountaineer Midstream since June 2013, (iv) Ohio

EX 99.2-11

EXHIBIT 99.2

Gathering since January 2014, (v) Tioga Midstream since April 2014 and (vi) Summit Utica since December 2014. The financial position, results of operations and cash flows of Bison Midstream, 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 purchase price 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. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. We combined the balances associated with the unfavorable gas gathering contract with other noncurrent liabilities. These balance sheet changes had no impact on (i) total liabilities or (ii) total liabilities and partners' capital.

We also evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts and (ii) certain pass-through expenses also for Bison Midstream. As a result of this evaluation, we determined that certain amounts that had previously been recognized in cost of natural gas and NGLs would be more appropriately reflected as gathering services and related fees and other revenues to enhance reporting transparency. The impact of these reclassifications, which had no impact on net (loss) income, total partners' capital or segment adjusted EBITDA, follows.

	Year ended December 31,
	2014		2013
	(In thousands)
Gathering services and related fees	$	15,616	$	16,805
Other revenues	3,952		10,068
Net impact on total revenues	$	19,568	$	26,873
Cost of natural gas and NGLs	$	19,568	$	26,873
Net impact on cost of natural gas and NGLs and total costs and expenses	$	19,568	$	26,873

In the fourth quarter 2015, we began reporting all of our operations in North Dakota as one reportable segment, the Williston Basin reportable segment. This presentation change had no impact on total assets, total liabilities, total revenues, total costs and expenses, net income, partners' capital, cash flows or total segment adjusted EBITDA. See Note 3 for additional information on this change.

In the first quarter of 2016, we adopted Accounting Standards Update ("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 deferred loan costs from other noncurrent assets to long-term debt at December 31, 2015 and $10.8 million at December 31, 2014 (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.

EX 99.2-12

EXHIBIT 99.2

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.

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.

	Useful lives (In years)
Gathering and processing systems and related equipment	30
Other	4-15

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, 2015 or 2014.

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 on a units-of-production basis 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

EX 99.2-13

EXHIBIT 99.2

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.

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 deferred loan costs over the life of the revolving credit facility. We recognize amortization of deferred loan costs in interest expense.

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 our DFW Midstream customers and our procurement of electricity to operate DFW Midstream's electric-drive compression assets. Our gas gathering agreements with our 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 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 also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas 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:

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

EX 99.2-14

EXHIBIT 99.2

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

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

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.

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 our 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 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:

• Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, and/or processing and (ii) crude oil and/or produced water gathering.

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

Certain of our gathering and processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("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.

EX 99.2-15

EXHIBIT 99.2

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 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 statement of operations over the vesting period of the respective awards.

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.

In 2014, we elected to apply changes to the determination of cost of goods sold for the Texas Margin Tax which permits the use of accelerated depreciation allowed for federal income tax purposes.  As a result of this change, we recognized a deferred tax liability. Other noncurrent liabilities included a deferred tax liability of $0.6 million and $1.6 million as of December 31, 2015 and 2014, respectively.

Earnings or Loss Per Unit ("EPU"). 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) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (ii) the general partner's 2% interest in net income or loss and (iii) 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 receipt is deemed probable.

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

EX 99.2-16

EXHIBIT 99.2

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.

Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with debt incurred by SMP or its affiliates which was replaced with bank borrowings or debt capital at the Partnership, we allocate a portion of that debt, net of deferred loan 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. There are currently no recent pronouncements that have been issued that we believe may materially affect our financial statements, except as noted below.

In May 2014, the FASB released a joint revenue recognition standard, ASU No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) the Company satisfies a performance obligation. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted.  In July 2015, the FASB reaffirmed the guidance in its April 2015 proposed ASU that defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We are currently in the process of evaluating the impact of this update.

In April 2015, the FASB issued ASU 2015-03. Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. This presentation will result in debt issuance cost being presented the same way debt discounts have historically been handled. In August 2015, the FASB amended ASU 2015-03 to address the presentation and subsequent measurement of debt issuance costs related to line of credit (“LOC”) arrangements. The amendment added a paragraph that states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of a LOC arrangement, regardless of whether there are outstanding borrowings under that LOC arrangement.  This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter.  Early adoption is permitted. The adoption of this update has resulted in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes. Debt issuance costs associated with our revolving credit facility will remain in other noncurrent assets. This ASU had no impact on interest expense, net income or loss, EPU or partners' capital.

In September 2015, the FASB issued ASU No. 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). Under ASU 2015-16, an acquirer would be required to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the acquirer must record in the financial statements for the same period, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Entities must also present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter.  Early adoption is permitted. We are currently in the process of evaluating the impact of this update.

EX 99.2-17

EXHIBIT 99.2

In January 2016, the FASB issued ASU No. 2016-01 Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Among other changes, the amendments in ASU 2016-01 supersede the guidance to classify equity securities with readily determinable fair values into different categories and require equity securities to be measured at fair value with changes in the fair value recognized through net income. They also simplify the impairment assessment of equity investments without readily determinable fair values and require use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes. Under ASU 2016-01, an entity will be required to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, to separately present financial assets and financial liabilities by measurement category and form of financial asset. ASU 2016-01 also clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 31, 2017. Early adoption is permissible, but limited in application. The adoption of this new update could impact the fair value we disclose for certain financial instruments but is not expected to impact amounts recognized in the consolidated financial statements.

3. SEGMENT INFORMATION

As of December 31, 2015, our reportable segments are:

• the Utica Shale, which includes our ownership interest in Ohio Gathering and also is served by Summit Utica;

• the Williston Basin, which is served by Bison Midstream, Polar and Divide and Tioga Midstream;

• the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;

• the Barnett Shale, which is served by DFW Midstream; and

• the Marcellus Shale, which is served by Mountaineer Midstream.

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, our investment in Ohio Gathering is included in the Utica Shale reportable segment. Segment assets for the Utica Shale includes the associated investment in equity method investees. 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.

In connection with the Polar and Divide Drop Down, we identified two reportable segments in the Williston Basin. For the second and third quarters of 2015, we reported the results of Bison Midstream in the Williston Basin – Gas reportable segment and those of Polar and Divide in the Williston Basin – Liquids reportable segment. In the fourth quarter of 2015, we changed how we manage and evaluate our operations in North Dakota. Prior to the fourth quarter of 2015, Bison Midstream and Polar and Divide were managed separately and their financial results were evaluated separately. In the fourth quarter of 2015, we began managing our North Dakota operations under a single management team and began reporting their financial results on a combined basis. As a result, we no longer distinguish between liquids and gas in the Williston Basin and now have one reportable segment, the Williston Basin reportable segment, representing those operations.

Corporate represents those assets and liabilities and revenues and expenses that are not specifically attributable to a reportable segment, not individually reportable, or that have not been allocated to our reportable segments. Beginning in the first quarter of 2015, we discontinued allocating certain general and administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.

EX 99.2-18

EXHIBIT 99.2

Assets by reportable segment follow.

	December 31,
	2015		2014		2013
	(In thousands)
Assets:
Utica Shale (1)	$	886,224	$	735,587	$	—
Williston Basin	740,361		861,461		680,014
Piceance/DJ Basins	866,095		941,382		936,794
Barnett Shale	416,586		428,935		431,578
Marcellus Shale	233,116		243,884		214,379
Total reportable segment assets	3,142,382		3,211,249		2,262,765
Corporate	22,290		31,213		19,281
Total assets	$	3,164,672	$	3,242,462	$	2,282,046

__________

(1) Represents the investment in equity method investees for Ohio Gathering (see Note 7) and total assets for Summit Utica.

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.

Revenues by reportable segment follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Revenues:
Utica Shale	$	4,700	$	190	$	—
Williston Basin	98,929		109,807		81,501
Piceance/DJ Basins	180,418		161,477		129,747
Barnett Shale	88,042		93,001		105,324
Marcellus Shale	28,468		22,694		9,588
Total reportable segment revenues and total revenues	$	400,557	$	387,169	$	326,160

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

	Year ended December 31,
	2015		2014		2013
Percentage of total revenues (1):
Counterparty A - Piceance/DJ Basins	16	%	18	%	19	%
Counterparty B - Piceance/DJ Basins	14	%	*		*
Counterparty C - Barnett Shale	*		*		14	%

__________

(1) Includes recognition of revenue that was previously deferred in connection with minimum volume commitments (see Notes 2 and 8).

* Less than 10%

EX 99.2-19

EXHIBIT 99.2

Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Depreciation and amortization:
Utica Shale	$	1,417	$	—	$	—
Williston Basin	31,376		24,027		16,669
Piceance/DJ Basins	47,433		42,959		36,185
Barnett Shale	16,392		16,601		14,961
Marcellus Shale	8,682		7,648		3,998
Total reportable segment depreciation and amortization	105,300		91,235		71,813
Corporate	603		587		451
Total depreciation and amortization	$	105,903	$	91,822	$	72,264

Capital expenditures by reportable segment follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Capital expenditures:
Utica Shale	$	94,994	$	24,787	$	—
Williston Basin	147,477		227,283		129,236
Piceance/DJ Basins	21,144		42,417		88,104
Barnett Shale	6,875		14,567		29,534
Marcellus Shale	1,306		33,866		1,822
Total reportable segment capital expenditures	271,796		342,920		248,696
Corporate	429		460		930
Total capital expenditures	$	272,225	$	343,380	$	249,626

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) impairments and (vi) 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 total revenues less total expenses, plus amortization for deferred contract costs multiplied by our ownership interest in Ohio Gathering during the respective period.

EX 99.2-20

EXHIBIT 99.2

Segment adjusted EBITDA by reportable segment follows.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	35,873	$	6,176	$	—
Williston Basin	34,008		30,009		17,350
Piceance/DJ Basins	110,222		110,763		79,687
Barnett Shale	59,526		60,528		69,473
Marcellus Shale	23,214		15,940		6,333
Total reportable segment adjusted EBITDA	$	262,843	$	223,416	$	172,843

__________

(1) Includes our proportional share of adjusted EBITDA for Ohio Gathering and is reflected as the proportional adjusted EBITDA for equity method investees in the reconciliation of income or loss before income taxes to segment adjusted EBITDA.

A reconciliation of (loss) income before income taxes to total reportable segment adjusted EBITDA follows.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Reconciliation of income (loss) before income taxes to segment adjusted EBITDA:
(Loss) income before income taxes	$	(216,268	)	$	(29,802	)	$	47,737
Add:
Allocated corporate expenses	27,352			15,441			10,153
Interest expense	59,092			48,586			21,314
Depreciation and amortization	105,903			91,822			72,264
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based and noncash compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
Interest income	2			4			5
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Total reportable segment adjusted EBITDA	$	262,843		$	223,416		$	172,843

Segment adjusted EBITDA excludes the effect of allocated corporate expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, interest expense and income tax expense.

Adjustments related to MVC shortfall payments account for:

• the net increases or decreases in deferred revenue for MVC shortfall payments and

• our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our consolidated financial statements.

EX 99.2-21

EXHIBIT 99.2

Adjustments related to MVC shortfall payments by reportable segment follow.

	Year ended December 31,
	2015			2014		2013
	(In thousands)
Adjustments related to MVC shortfall payments:
Williston Basin	$	11,870		$	10,743	$	3,600
Piceance/DJ Basins	(21,590		)	15,194		12,395
Barnett Shale	(2,182		)	628		1,030
Total adjustments related to MVC shortfall payments	$	(11,902	)	$	26,565	$	17,025

4. PROPERTY, PLANT, AND EQUIPMENT, NET

Details on property, plant, and equipment follow.

	December 31,
	2015		2014
	(In thousands)
Gathering and processing systems and related equipment	$	1,883,139	$	1,630,250
Construction in progress	75,132		48,500
Land and line fill	11,055		11,057
Other	32,427		58,375
Total	2,001,753		1,748,182
Less accumulated depreciation	188,970		125,542
Property, plant, and equipment, net	$	1,812,783	$	1,622,640

During 2015 and 2014, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired. (There were no impairment indicators during 2013.) 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.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Long-lived asset impairment:
Williston Basin	$	7,554	$	—	$	—
Barnett Shale	531		5,505		—
Piceance/DJ Basins	1,220		—		—

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.

EX 99.2-22

EXHIBIT 99.2

Depreciation expense and capitalized interest follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Depreciation expense	$	63,915	$	53,064	$	37,947
Capitalized interest	3,372		4,646		6,690

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.

	December 31, 2015
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(9,534	)	$	14,661
Contract intangibles	12.5	426,464		(111,052		)	315,412
Rights-of-way	26.3	150,143		(18,906		)	131,237
Total intangible assets		$	600,802	$	(139,492	)	$	461,310
Unfavorable gas gathering contract	10.0	$	10,962	$	(6,077	)	$	4,885

	December 31, 2014
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(8,056	)	$	16,139
Contract intangibles	12.5	426,464		(75,713		)	350,751
Rights-of-way	27.0	135,435		(13,043		)	122,392
Total intangible assets		$	586,094	$	(96,812	)	$	489,282
Unfavorable gas gathering contract	10.0	$	10,962	$	(5,385	)	$	5,577

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.

We recognized amortization expense in other revenues as follows:

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(1,478	)	$	(1,741	)	$	(2,078	)
Amortization expense – unfavorable gas gathering contract	692			797			1,046

EX 99.2-23

EXHIBIT 99.2

We recognized amortization expense in costs and expenses as follows:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Amortization expense – contract intangibles	$	35,339	$	32,554	$	28,654
Amortization expense – rights-of-way	5,863		5,260		4,631

The estimated aggregate annual amortization expected to be recognized as of December 31, 2015 for each of the five succeeding fiscal years follows.

	Intangible assets		Unfavorable gas gathering contract
	(In thousands)
2016	$	43,108	$	924
2017	41,959		1,047
2018	41,413		1,035
2019	41,659		1,045
2020	44,305		834

6. GOODWILL

Recorded 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.

	Piceance/DJ Basins			Williston Basin			Marcellus Shale		Total
	(In thousands)
Goodwill, January 1, 2014	$	45,478		$	257,572		$	16,211	$	319,261
Goodwill impairment	—			(54,199		)	—		(54,199		)
Goodwill, December 31, 2014	45,478			203,373			16,211		265,062
Goodwill impairment	(45,478		)	(203,373		)	—		(248,851		)
Goodwill, December 31, 2015	$	—		$	—		$	16,211	$	16,211

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

	December 31,
	2015		2014		2013
	(In thousands)
Accumulated goodwill impairment:
Piceance/DJ Basins	$	45,478	$	—	$	—
Williston Basin	257,572		54,199		—
Total accumulated goodwill impairment	$	303,050	$	54,199	$	—

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.

EX 99.2-24

EXHIBIT 99.2

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.

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.

EX 99.2-25

EXHIBIT 99.2

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.

Our preliminary estimates of the fair values of the identified assets and liabilities calculated in step two indicated that all of the associated goodwill for both reporting units had been impaired. As such, we recorded an estimated goodwill impairment of $45.5 million for Grand River and $203.4 million for Polar and Divide. These amounts represent our estimate of impairment pending finalization of the fair value calculations. We expect finalization to occur in the first quarter of 2016.

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.

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 1.0% 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 1.0% ownership interest.

The ownership interest Summit Investments acquired from Blackhawk included an option to increase the holder's ownership interest in Ohio Gathering to 40.0% (the "Option"). In May 2014, Summit Investments exercised the Option to increase its ownership to 40.0% (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 40.0% 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 60.0% 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.

EX 99.2-26

EXHIBIT 99.2

Subsequent to the Option Exercise, Summit Investments continued to make capital contributions to Ohio Gathering along with receiving distributions such that it maintained its 40.0% 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.

A rollforward of the investment in equity method investees follows.

	2015			2014
	(In thousands)
Investment in equity method investees, January 1	$	706,172		$	—
Cash contributions	86,200			145,131
Cash distributions	(34,641		)	(2,992		)
Gain (loss) from equity method investees	6,790			(4,472		)
Amortization of basis difference in equity method investees	(13,353		)	(12,240		)
Acquisition of initial interest in Ohio Gathering	—			190,000
January 2014 initial cash contribution	—			8,360
Option Exercise	—			382,385
Investment in equity method investees, December 31	751,168			706,172
December cash distributions	3,472			—
December cash contributions	—			(20,420		)
Basis difference	(156,888		)	(170,241		)
Investment in equity method investees, net of basis difference, November 30	$	597,752		$	515,511

The following table presents summarized balance sheet information for Ohio Gathering.

	November 30,
	2015		2014
	(In thousands)
Total assets	$	1,510,075	$	1,341,007
Total liabilities	59,313		95,391
Members' equity	1,450,762		1,245,616

The following table presents summarized statements of operations information for Ohio Gathering for the twelve months ended November 30, 2015 and for the period of ownership in 2014.

	Twelve months ended November 30, 2015		Ten months ended November 30, 2014
	(In thousands)
Total revenues	$	130,090	$	45,313
Total operating expenses	112,581		66,374
Net income (loss)	16,803		(21,061		)

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.

EX 99.2-27

EXHIBIT 99.2

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:

• To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of that customer's MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable).

• To the extent that a customer's throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply will be less than the weighted-average of the original stated contract terms of our MVCs.

• To the extent that certain of our customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.

A rollforward of current deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2014	$	—	$	—	$	1,555	$	1,555
Additions	—		—		2,610		2,610
Less revenue recognized	—		—		1,788		1,788
Current deferred revenue, December 31, 2014	—		—		2,377		2,377
Additions	—		2,743		677		3,420
Less revenue recognized	—		2,743		2,377		5,120
Current deferred revenue, December 31, 2015	$	—	$	—	$	677	$	677

A rollforward of noncurrent deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2014	$	6,389	$	23,294	$	—	$	29,683
Additions	10,743		14,813		—		25,556
Noncurrent deferred revenue, December 31, 2014	17,132		38,107		—		55,239
Additions	11,897		12,765		—		24,662
Less revenue recognized	27		34,388		—		34,415
Noncurrent deferred revenue, December 31, 2015	$	29,002	$	16,484	$	—	$	45,486

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 area of mutual interest ("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

EX 99.2-28

EXHIBIT 99.2

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, 2015, accounts receivable included $12.7 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods.

9. DEBT

Debt consisted of the following:

	December 31,
	2015			2014
	(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (2.93% at December 31, 2015 and 2.67% at December 31, 2014) due November 2018	$	344,000		$	208,000
Summit Holdings 5.50% Senior unsecured notes due August 2022	300,000			300,000
Less unamortized deferred loan costs (1)	(4,139		)	(4,773		)
Summit Holdings 7.50% Senior unsecured notes due July 2021	300,000			300,000
Less unamortized deferred loan costs (1)	(5,091		)	(6,020		)
SMP Holdings variable rate senior secured revolving credit facility (2.43% at December 31, 2015 and 2.17% at December 31, 2014) due February 2019 (2)	115,000			35,000
SMP Holdings variable rate senior secured term loan (2.43% at December 31, 2015 and 2.17% at December 31, 2014) due May 2017 (2)	217,500			400,000
Total long-term debt	$	1,267,270		$	1,232,207

__________

(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 Initial Close.

The aggregate amount of debt maturing during each of the years after December 31, 2015 are as follows:

	Debt
	(In thousands)
2016	$	—
2017 (1)	217,500
2018	344,000
2019 (1)	115,000
2020	—
Thereafter	600,000
Total long-term debt	$	1,276,500

__________

(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 Initial Close.

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"). The revolving credit facility has a $700.0 million borrowing capacity, matures in November 2018, and includes a $200.0 million accordion feature.

Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("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, 2015, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 2.93% and the unused portion of the revolving credit facility totaled $356.0 million (subject to a commitment fee of 0.50%).

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)

EX 99.2-29

EXHIBIT 99.2

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.

On February 25, 2016, we closed on an amendment to the revolving credit facility, which became effective concurrent with the March 3, 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 5.50 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.

As of December 31, 2015, 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, 2015.

Guarantees at December 31, 2015. As of December 31, 2015, the revolving credit facility was secured by the membership interests of Summit Holdings and those of its subsidiaries and substantially all of Summit Holdings' and its then-subsidiaries' assets were pledged as collateral under the revolving credit facility. Additionally, the revolving credit facility, and Summit Holdings' obligations, were guaranteed by SMLP and each of its subsidiaries.

Guarantee Subsequent Event. Following the 2016 Drop Down in March 2016, OpCo GP, OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream became 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 which removed the guarantees of OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream ("Non-Guarantor Subsidiaries"). Following execution of the consent and waiver agreement, the Guarantor Subsidiaries group included Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream Services and OpCo GP. For additional information, see Note 17.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes" and together with the 5.5% senior notes, the "Senior Notes").

Guarantees at December 31, 2015. As of December 31, 2015, Bison Midstream and its subsidiaries, Grand River and its subsidiary and DFW Midstream Services (collectively, the "Guarantor Subsidiaries") and SMLP have fully and unconditionally and jointly and severally guaranteed the Senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility and the Senior Notes. Finance Corp. has no assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan.

Guarantee Subsequent Event. As noted above, a consent and waiver agreement was executed in August 2016 with an effective date of March 30, 2016 which removed the guarantees of Non-Guarantor Subsidiaries from the Senior Notes. Following execution of the consent and waiver agreement, the Senior Notes are guaranteed by SMLP, Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream Services and OpCo GP.

5.5% Senior Notes. We will pay interest on the 5.5% senior notes semi-annually in cash in arrears on February 15 and August 15 of each year, commencing February 15, 2015. The 5.5% senior notes are senior, unsecured obligations and rank equally in right of 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

EX 99.2-30

EXHIBIT 99.2

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, 2015, 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, 2015.

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 of 1933, as amended (the "Securities Act"), and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act.

We pay interest on the 7.5% senior notes semi-annually in cash in arrears on January 1 and July 1 of each year. The 7.5% senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 7.5% 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 7.5% senior notes to repay a portion of the balance outstanding under our revolving credit facility.

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 are 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 do not apply to the registered senior notes.

At any time prior to July 1, 2016, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 7.5% senior notes at a redemption price of 107.500% of the principal amount of the 7.5% 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 July 1, 2016, the Co-Issuers may 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

EX 99.2-31

EXHIBIT 99.2

and after July 1, 2019), plus accrued and unpaid interest, if any. Debt issuance costs of $7.4 million are being amortized over the life of the senior notes.

The 7.5% 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 7.5% 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 7.5% senior notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 7.5% 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 7.5% 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 7.5% 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 7.5% senior notes may declare all the 7.5% senior notes to be due and payable immediately.

As of December 31, 2015, 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, 2015.

SMP Holdings Credit Facility. In March 2013, SMP Holdings closed on a $150.0 million senior secured revolving credit facility (the "SMP Revolving Credit Facility") and a $200.0 million senior secured term loan (the "Term Loan" and, collectively with the SMP Revolving Credit Facility, the "SMP Holdings Credit Facility"). Borrowings under the SMP Holdings Credit Facility incurred interest at LIBOR or a base rate (as defined in the SMP Holdings Credit Facility) plus an applicable margin. Because the funding 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 years ended December 31, 2015, 2014 and 2013.

In February 2014, SMP Holdings closed on an amendment and restatement of the SMP Holdings Credit Facility whereby it:

(i) increased the borrowing capacity from $150.0 million to $250.0 million;

(ii) extended the maturity date from March 2018 to February 2019;

(iii) added a $100.0 million revolving credit facility accordion feature and a $400.0 million term loan accordion;

(iv) reduced the leverage-based pricing grid by 0.75% from a range of 2.75% to 3.75% to a new range of 2.00% to 3.00% for LIBOR borrowings and from a range of 1.75% to 2.75% to a new range of 1.00% to 2.00% for alternate base rate borrowings;

(v) changed the commitment fee from 0.50% to a leverage-based range of 0.30% to 0.50%; and

(vi) increased the maximum total leverage ratio from 4.0 to 1.0 to 5.0 to 1.0 and from not more than 5.0 to 1.0 to 5.5 to 1.0 for up to 270 days following certain acquisitions, or material projects or, at its option, after a qualified notes offering (as defined in the SMP Holdings Credit Facility).

In March 2014, Summit Investments used the proceeds from its offering of SMLP common units to repay the remaining $100.0 million balance on the then-outstanding Term Loan as well as $95.0 million then outstanding under the SMP Revolving Credit Facility. It wrote off $1.5 million of deferred loan costs in connection with these repayments. In May 2014, Summit Investments borrowed $400.0 million pursuant to the Term Loan accordion (the

EX 99.2-32

EXHIBIT 99.2

"Incremental Term Loan"). In May 2015, it repaid $175.0 million of the Incremental Term Loan and wrote off $0.7 million of deferred loan costs in connection therewith.

On March 3, 2016, the remaining balances on the SMP Revolving Credit Facility and the Incremental Term Loan were repaid in full and the SMP Holdings Credit Facility was terminated concurrent with the closing of the 2016 Drop Down (see Note 16).

The SMP Holdings Credit Facility contained affirmative and negative covenants customary for credit facilities of its size and nature. As of December 31, 2015, Summit Investments was in compliance with the covenants in the SMP Holdings Credit Facility. There were no defaults or events of default during the year ended December 31, 2015 or during the period from December 31, 2015 to the March 3, 2016 termination of the SMP Holdings Credit Facility.

10. FINANCIAL INSTRUMENTS

Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and accounts receivable. We maintain our cash 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 68% of total accounts receivable at December 31, 2015, compared with 57% as of December 31, 2014.

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

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

	December 31, 2015				December 31, 2014
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings revolving credit facility	$	344,000	$	344,000	$	208,000	$	208,000
Summit Holdings 5.5% senior notes ($300.0 million principal)	295,861		224,000		295,227		281,750
Summit Holdings 7.5% senior notes ($300.0 million principal)	294,909		257,000		293,980		306,750
SMP Holdings revolving credit facility (1)	115,000		115,000		35,000		35,000
SMP Holdings term loan (1)	217,500		217,500		400,000		400,000

__________

(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 Initial 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, 2015 and December 31, 2014. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

EX 99.2-33

EXHIBIT 99.2

11. PARTNERS' CAPITAL

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

	Common	Subordinated	General partner	Total
Units, January 1, 2013	24,412,427	24,409,850	996,320	49,818,597
Units issued to a subsidiary of Summit Investments in connection with the Bison Drop Down	1,553,849	—	31,711	1,585,560
Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition	3,107,698	—	63,422	3,171,120
Net units issued under SMLP LTIP	5,892	—	—	5,892
Units, January 1, 2014	29,079,866	24,409,850	1,091,453	54,581,169
Units issued in connection with the March Equity 2014 Offering	5,300,000	—	108,337	5,408,337
Net units issued under SMLP LTIP	46,647	—	861	47,508
Units, December 31, 2014	34,426,513	24,409,850	1,200,651	60,037,014
Units issued in connection with the May 2015 Equity Offering	7,475,000	—	152,551	7,627,551
Net units issued under SMLP LTIP	161,131	—	1,498	162,629
Units, December 31, 2015	42,062,644	24,409,850	1,354,700	67,827,194

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 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, a subsidiary of Summit Investments completed an underwritten public offering of 4,347,826 SMLP common units 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 2% general partner interest.

Subordination. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution ("MQD," as defined below) plus any arrearages in the payment of the MQD from prior quarters. The subordination period ends on the first business day after we have earned and paid at least $1.60 (the MQD on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015. 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.

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. During the years ended December 31, 2015, 2014 and 2013, net income was attributed to Summit Investments for:

• the 2016 Drop Down Assets for the period from February 16, 2013 to March 3, 2016;

• Polar and Divide for the period from February 16, 2013 to May 18, 2015;

EX 99.2-34

EXHIBIT 99.2

• Red Rock Gathering for the period from January 1, 2013 to March 18, 2014; and

• Bison Midstream for the period from February 16, 2013 to June 4, 2013.

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

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 (dollars in thousands).

Summit Investments' net investment in Polar Midstream and Epping			$	416,044
Total net cash consideration paid to a subsidiary of Summit Investments			285,677
Excess of acquired carrying value over consideration paid			$	130,367
Allocation of capital contribution:
General partner interest	$	2,607
Common limited partner interest	80,079
Subordinated limited partner interest	47,681
Partners' capital contribution – excess of acquired carrying value over consideration paid			$	130,367

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 (dollars in thousands).

Summit Investments' net investment in Red Rock Gathering				$	241,817
Total net cash consideration paid to a subsidiary of Summit Investments				307,941
Excess of consideration paid over acquired carrying value				$	(66,124	)
Allocation of capital distribution:
General partner interest	$	(1,323	)
Common limited partner interest	(37,910		)
Subordinated limited partner interest	(26,891		)
Partners' capital distribution – excess of consideration paid over acquired carrying value				$	(66,124	)

Bison Drop Down. On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. In exchange for its $305.4 million net investment in Bison Midstream, SMLP paid Summit Investments and the general partner total cash and unit consideration of $248.9 million. As a result of the contribution of net assets in excess of consideration, SMLP recognized a capital contribution from Summit Investments.

EX 99.2-35

EXHIBIT 99.2

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

Summit Investments' net investment in Bison Midstream			$	305,449
Aggregate cash paid to Summit Investments	$	200,000
Issuance of 1,553,849 SMLP common units to Summit Investments	47,936
Issuance of 31,711 SMLP general partner units to the general partner	978
Total consideration paid to a subsidiary of Summit Investments			248,914
Excess of acquired carrying value over consideration paid			$	56,535
Allocation of capital contribution:
General partner interest	$	1,131
Common limited partner interest	28,558
Subordinated limited partner interest	26,846
Partners' capital contribution – excess of acquired carrying value over consideration paid			$	56,535

The number of units issued to Summit Investments and the general partner in connection with the Bison Drop Down was calculated based on an assumed equity issuance of $50.0 million and the five-day volume-weighted-average price as of June 3, 2013 of $31.53 per unit. The units were then valued as of June 4, 2013 (the date of closing) using the June 4, 2013 closing price of SMLP's units of $30.85.

The general partner interest allocation was calculated based on a 2% general partner interest in the contribution of assets in excess of consideration given by SMLP to Summit Investments. Common and subordinated limited partner interests allocations were calculated as their respective percentages of total limited partner capital applied to the balance of the contribution by Summit Investments after giving effect to the general partner allocation.

Mountaineer Acquisition. We completed the acquisition of Mountaineer Midstream on June 21, 2013. The purchase price of $210.0 million was funded with $110.0 million of borrowings under SMLP’s revolving credit facility and the issuance for cash of $100.0 million of SMLP common units and general partner interests to a subsidiary of Summit Investments and the general partner.

The allocation and valuation of units issued to partially fund the Mountaineer Acquisition follow (dollars in thousands).

Issuance of 3,107,698 SMLP common units to Summit Investments	$	98,000
Issuance of 63,422 SMLP general partner units to the general partner	2,000
Issuance of units in connection with the Mountaineer Acquisition	$	100,000

Pursuant to a unit purchase agreement, the number of units issued to Summit Investments and the general partner in connection with the Mountaineer Acquisition was calculated based on an assumed equity issuance of $100.0 million and the five-day volume-weighted-average price as of June 3, 2013 of $31.53 per unit.

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.

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

Minimum Quarterly Distribution.Our partnership agreement generally requires that we make a minimum quarterly distribution to the holders of our common units and subordinated 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

EX 99.2-36

EXHIBIT 99.2

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:

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

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

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

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

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

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

	Year ended December 31,
	2015		2014		2013
Per-unit annual distributions to unitholders	$	2.270	$	2.040	$	1.725

On January 21, 2016, the board of directors of our general partner declared a distribution of $0.575 per unit for the quarterly period ended December 31, 2015. This distribution, which totaled $41.0 million, was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016. As noted above, the payment of this distribution triggered the end of the subordination period and all of the then-outstanding subordinated units converted to common units on a one-for-one basis on February 16, 2016.

We allocated the February 2016 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, up to a maximum of 50.0% (as set forth in the chart below), of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution does not include any distributions that our general partner may receive on any common or subordinated units that it owns.

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 minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units.

EX 99.2-37

EXHIBIT 99.2

	Total quarterly distribution per unit target amount	Marginal percentage interest in distributions
		Unitholders	General partner
Minimum quarterly distribution	$0.40	98.0%	2.0%
First target distribution	$0.40 up to $0.46	98.0%	2.0%
Second target distribution	above $0.46 up to $0.50	85.0%	15.0%
Third target distribution	above $0.50 up to $0.60	75.0%	25.0%
Thereafter	above $0.60	50.0%	50.0%

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 statement of partners' capital during the years ended December 31 follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
IDR payments	$	6,743	$	2,326	$	—

Our general partner was not entitled to receive IDR payments prior to the distribution declared and paid in respect of the fourth quarter of 2013 based on the amount of the distributions declared and paid per common and subordinated unit.

For the purposes of calculating net income attributable to general partner, 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.

12. EARNINGS PER UNIT

The following table details the components of EPU.

	Year ended December 31,
	2015			2014			2013
	(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net (loss) income among limited partner interests:
Net (loss) income attributable to common units	$	(125,437	)	$	(16,324	)	$	23,227
Net (loss) income attributable to subordinated units	(70,173		)	(10,793		)	19,322
Net (loss) income attributable to limited partners	$	(195,610	)	$	(27,117	)	$	42,549
Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	39,217			33,311			26,951
Effect of nonvested phantom units	—			—			150
Weighted-average common units outstanding – diluted	39,217			33,311			27,101
Weighted-average subordinated units outstanding – basic and diluted	24,410			24,410			24,410
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.20	)	$	(0.49	)	$	0.86
Common unit – diluted	$	(3.20	)	$	(0.49	)	$	0.86
Subordinated unit – basic and diluted	$	(2.88	)	$	(0.44	)	$	0.79

EX 99.2-38

EXHIBIT 99.2

During the years ended December 31, 2015 and 2014, we excluded 109,201 and 231,875 units, respectively, in our calculation of the effect of nonvested phantom units because they were anti-dilutive. There were no anti-dilutive units during for the year ended December 31, 2013.

13. UNIT-BASED AND NONCASH COMPENSATION

SMLP Long-Term Incentive Plan. The 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, 2015, approximately 4.4 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.

The following table presents phantom and restricted unit activity:

	Units		Weighted-average grant date fair value
Nonvested phantom and restricted units, January 1, 2013	131,558		$	20.00
Phantom and restricted units granted	156,165		26.33
Phantom units forfeited	(4,041	)	25.99
Nonvested phantom and restricted units, December 31, 2013	283,682		23.41
Phantom units granted	136,867		42.32
Phantom and restricted units vested	(61,917	)	25.33
Phantom units forfeited	(22,430	)	25.56
Nonvested phantom units, December 31, 2014	336,202		30.61
Phantom units granted	289,735		29.21
Phantom units vested	(229,497	)	27.66
Phantom units forfeited	(16,529	)	35.09
Nonvested phantom units, December 31, 2015	379,911		$	31.13

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

EX 99.2-39

EXHIBIT 99.2

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.

As of December 31, 2015, the unrecognized unit-based compensation related to the SMLP LTIP was $5.5 million. Incremental unit-based compensation will be recorded over the remaining vesting period of approximately 1.17 years. Due to the limited and immaterial forfeiture history associated with the grants under the SMLP LTIP, no forfeitures were assumed in the determination of estimated compensation expense.

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

	Year ended December 31,
	2015		2014		2013
	(In thousands)
SMLP LTIP unit-based compensation	$	6,174	$	4,696	$	2,999

SMP Net Profits Interests. In connection with the formation of Summit Investments in 2009, up to 7.5% of total membership interests were authorized for issuance. SMP Net Profits Interests were granted through January 2012. Each grant vests ratably over five years and provides for accelerated vesting in certain limited circumstances. Summit Investments valued the SMP Net Profits Interests utilizing an option pricing method, which modeled membership interests as call options on the underlying equity value of Summit Investments and considered the rights and preferences of each class of equity to allocate a fair value to each class. Summit Investments retained the SMP Net Profits Interests and, as such, they are not reflected in SMLP's financial statements subsequent to the IPO, except as noted below.

Due to common control, we recognized the SMP Net Profits Interests' noncash compensation expense that had been allocated to the contributed subsidiaries prior to their respective drop down date. Noncash compensation recognized in general and administrative expense related to the SMP Net Profits Interests was $0.8 million in 2015, $1.1 million in 2014 and $1.2 million in 2013.

DFW Net Profits Interests. In connection with the formation of DFW Midstream in 2009, up to 5% of DFW Midstream's total membership interests were authorized for issuance (the "DFW Net Profits Interests"). Grants were made in 2009 and 2010. Each grant vested ratably over four years and provided for accelerated vesting in certain limited circumstances. The DFW Net Profits Interests were valued utilizing an option pricing method, which modeled membership interests as call options on the underlying equity value of DFW Midstream and considered the rights and preferences of each class of equity to allocate a fair value to each class.

Beginning in October 2012 and continuing into April 2013, we entered into a series of repurchases with the remaining seven holders of the then-outstanding DFW Net Profits Interests whereby we exchanged $12.2 million for their vested DFW Net Profits Interests and 7,393 SMLP restricted units for their unvested DFW Net Profits Interests. The repurchase prices were determined by valuing the vested and unvested net profits interests in relation to the enterprise value of DFW Midstream and represented fair value at the dates of repurchase. Upon the conclusion of these repurchase transactions, there were no remaining or outstanding DFW Net Profits Interests.

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, the Bison 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.

EX 99.2-40

EXHIBIT 99.2

Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Operation and maintenance expense	$	25,050	$	22,004	$	15,095
General and administrative expense	26,193		24,993		21,084

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

• certain support expenses and capital expenditures on behalf of the contributed subsidiaries. These transactions were settled periodically through membership interests prior to the respective drop down;

• interest expense that was related to capital projects for the contributed subsidiaries. As such, the associated interest expense was allocated to the respective contributed subsidiary's capital projects as a noncash contribution and capitalized into the basis of the asset; and

• SMP Net Profits Interests accounted for as compensatory awards. As such, the annual expense associated with the SMP Net Profits was allocated to the respective contributed subsidiary and is reflected in general and administrative expenses in the statement of operations.

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:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Rent expense	$	2,395	$	1,881	$	1,616

Future minimum lease payments for the Partnership's operating leases are immaterial.

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 gathering 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 currently available information, it is at least reasonably possible that the rupture occurred on or prior to December 31, 2014. As such, Summit Investments accounted for the rupture as a 2014 event.

EX 99.2-41

EXHIBIT 99.2

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 is covered by Summit Investments' insurance policies, is 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. Property and business interruption claim requests have been submitted, although no amounts have been recognized for any potential recoveries, under the property and business interruption insurance policy.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2014	$	—
Initial accrual	30,000
Accrued environmental remediation, December 31, 2014	30,000
Payments made by affiliates	(13,136		)
Payments made with proceeds from insurance policies	(25,000		)
Additional accruals	21,800
Accrued environmental remediation, December 31, 2015	$	13,664

As of December 31, 2015, 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, 2016. 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, 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.

On June 19, 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, the Partnership acquired 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 consideration for the 2016 Drop Down Assets (i) consisted of a cash payment to SMP Holdings of $360.0 million (the “Initial Payment”), funded with borrowings under our revolving credit facility and (ii) includes a deferred payment in 2020 (the “Deferred Purchase Price Obligation”).  The Deferred Purchase Price Obligation will be equal to:

• six-and-one-half (6.5) multiplied by the average Business Adjusted EBITDA, as defined below and in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster, as defined in the Contribution Agreement;

• less the Initial Payment;

• less all capital expenditures incurred for the 2016 Drop Down Assets between the Initial Close and December 31, 2019;

EX 99.2-42

EXHIBIT 99.2

• plus all Business Adjusted EBITDA from the 2016 Drop Down Assets between Initial Close and December 31, 2019, less the Cumulative G&A Adjuster, as defined in the Contribution Agreement. 

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

• plus interest expense, income tax expense, and depreciation and amortization of the 2016 Drop Down Assets for such period;

• plus any adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses with respect to the 2016 Drop Down Assets for such period;

• plus any Special Liability Expenses, as defined below and in the Contribution Agreement, for such period;

• less interest income and income tax benefit of the 2016 Drop Down Assets for such period;

• less adjustments related to any other noncash income or gains with respect to 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, and 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 Initial Close, the Deferred Purchase Price Obligation was estimated to be $860.3 million (based on management’s estimate of the Partnership’s share of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets) and had a net present value of $507.4 million, using a discount rate of 13%.

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. As of December 31, 2014, we assigned the full purchase price to property, plant and equipment.

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

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 assets acquired 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 at acquisition, which reflected its fair value accounting for the initial acquisition of Meadowlark Midstream in 2013, due to common control.

EX 99.2-43

EXHIBIT 99.2

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

Purchase price assigned to Meadowlark Midstream			$	25,376
Current assets	$	2,227
Property, plant, and equipment	18,795
Other noncurrent assets	4,354
Total assets acquired	25,376
Total liabilities assumed	$	—
Net identifiable assets acquired			$	25,376

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 gathering 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) $92.5 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.

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

Purchase price assigned to Polar Midstream			$	216,105
Current assets	$	368
Property, plant, and equipment	9,755
Other noncurrent assets	7,201
Total assets acquired	17,324
Current liabilities	4,592
Total liabilities assumed	$	4,592
Net identifiable assets acquired			12,732
Goodwill			$	203,373

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

EX 99.2-44

EXHIBIT 99.2

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 ("Lonestar") 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 is accounting 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.

Bison Gas Gathering System.On February 15, 2013, Summit Investments acquired BTE. On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. The Bison Gas Gathering system was carved out from Meadowlark Midstream and primarily gathers associated natural gas production from customers operating in Mountrail and Burke counties in North Dakota under long-term contracts ranging from five years to 15 years. The weighted-average life of the acquired contracts was12 years upon acquisition.

Summit Investments accounted for its purchase of BTE (the "BTE Transaction") 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 February 15, 2013. The intangible assets that were acquired are composed of gas gathering agreement contract values and rights-of-way easements. 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.

Because the Bison Drop Down was executed between entities under common control, SMLP recognized the acquisition of the Bison Gas Gathering system at historical cost which reflected Summit Investments fair value accounting for the BTE Transaction. Furthermore, due to the common control aspect, the Bison Drop Down was accounted for by SMLP on an “as-if pooled” basis for all periods in which common control existed. Common control began on February 15, 2013 concurrent with the BTE Transaction.

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

Purchase price assigned to Bison Gas Gathering system			$	303,168
Current assets	$	5,705
Property, plant, and equipment	85,477
Intangible assets	164,502
Other noncurrent assets	2,187
Total assets acquired	257,871
Current liabilities	6,112
Other noncurrent liabilities	2,790
Total liabilities assumed	$	8,902
Net identifiable assets acquired			248,969
Goodwill			$	54,199

The Bison Drop Down closed on June 4, 2013. The total acquisition purchase price of $248.9 million was funded with $200.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $47.9 million of SMLP common units to Summit Investments and $1.0 million of general partner interests to SMLP’s general partner. Summit Investments had a net investment in the Bison Gas Gathering system of $303.2 million and received total consideration of $248.9 million from SMLP. As a result, SMLP recognized a capital contribution from Summit Investments for the contribution of net assets in excess of consideration paid.

Mountaineer Midstream. We completed the Mountaineer Acquisition on June 21, 2013 for $210.0 million cash consideration. The Mountaineer Midstream natural gas gathering and compression assets are located in the

EX 99.2-45

EXHIBIT 99.2

Appalachian Basin which includes the Marcellus Shale formation primarily in Doddridge and Harrison counties in northern West Virginia. The Mountaineer Midstream system consists of newly constructed, high-pressure gas gathering pipelines, certain rights-of-way associated with the pipeline, and two compressor stations. The assets gather natural gas under a long-term, fee-based contract with Antero Resources Corp. ("Antero"). The life of the acquired contract was 13 years upon acquisition.

The Mountaineer Acquisition was funded with $110.0 million of borrowings under the Partnership's revolving credit agreement and the issuance of $100.0 million of common and general partner interests to a subsidiary of Summit Investments. For the year ended December 31, 2013, SMLP recorded $9.6 million of revenue and $2.3 million of net income related to Mountaineer Midstream.

SMLP accounted for the Mountaineer Acquisition under the acquisition method of accounting. As of June 30, 2013, we preliminarily assigned the full $210.0 million purchase price to property plant and equipment. During the third quarter of 2013, we received additional information and, as a result, preliminarily assigned $158.3 million of the purchase price to property, plant and equipment, $27.1 million to contract intangibles, $6.5 million to rights-of-way and $18.1 million to goodwill. During the fourth quarter of 2013, we received additional information from the seller and finalized the purchase price allocation.

The final fair values of the assets acquired and liabilities assumed as of June 21, 2013, were as follows (in thousands):

Purchase price assigned to Mountaineer Midstream			$	210,000
Property, plant, and equipment	$	163,661
Gas gathering agreement contract intangibles	24,019
Rights-of-way	6,109
Total assets acquired	193,789
Total liabilities assumed	$	—
Net identifiable assets acquired			193,789
Goodwill			$	16,211

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 2016 Drop Down, Polar Midstream, Red Rock Gathering and the Bison Gas Gathering system have been combined to reflect the historical operations, financial position and cash flows 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.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
SMLP revenues	$	358,046		$	338,941		$	241,089
2016 Drop Down Assets revenues (1)	29,238			14,466			2,474
Polar and Divide revenues (1)	13,273			22,449			3,893
Red Rock Gathering revenues (1)				11,313			50,114
Bison Gas Gathering system revenues (1)							28,590
Combined revenues	$	400,557		$	387,169		$	326,160
SMLP net (loss) income	$	(192,212	)	$	(23,992	)	$	43,584
2016 Drop Down Assets net loss (1)	(35,419		)	(32,634		)	(5,829		)
Polar and Divide net income (loss) (1)	5,403			6,430			(467		)
Red Rock Gathering net income (1)				2,828			9,668
Bison Gas Gathering system net income (1)							52
Combined net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008

__________

(1) Results are fully reflected in SMLP's revenues and net income on the date common control began, see Note 1.

EX 99.2-46

EXHIBIT 99.2

Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that:

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

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

• Pro forma adjustments also reflect the impact of 4,661,547 common unit issuance and the general partner capital contribution to maintain its 2% general partner interest to fund the acquisition of Bison Midstream and Mountaineer Midstream.

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

• Pro forma adjustments (other than an adjustment for interest expense as discussed below) for the 2016 Drop Down Assets are not required because the assets were not in service prior to common control beginning in February 2013. Interest expense was assumed based on the impact of $360.0 million of incremental borrowings on our revolving credit facility, partially offset by the pro forma derecognition of interest expense allocated to the 2016 Drop Down Assets from Summit Investments (see Note 9).

• Pro forma adjustments for Polar and Divide are not required because the system was not in service prior to common control beginning in February 2013.

• The acquisition of the Lonestar assets is immaterial for pro forma purposes and as such has not been reflected below.

	Year ended December 31, 2013
	(In thousands, except for per-unit amounts)
Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues	$	87,196
Total Bison Midstream and Mountaineer Midstream net loss included in consolidated net income	(457		)
Pro forma total revenues	$	338,311
Pro forma net income	34,369
Pro forma common EPU - basic and diluted	$	0.68
Pro forma subordinated EPU - basic and diluted	0.62

The unaudited pro forma financial information presented above is not necessarily indicative of (i) what our financial position or results of operations would have been if the acquisitions of Bison Midstream and Mountaineer Midstream had occurred on January 1, 2012, or (ii) what SMLP’s financial position or results of operations will be for any future periods.

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In July 2014 and June 2013, the Co-Issuers issued the Senior Notes. As of December 31, 2015, the Senior Notes were fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the then-Guarantor Subsidiaries and SMLP. Due to the common control nature of the 2016 Drop Down, we are including the following supplemental condensed consolidating financial information. This 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 as-if the guarantor structure that exists subsequent to the August 2016 consent and waiver agreement was executed prior to 2016 (see Note 9).

EX 99.2-47

EXHIBIT 99.2

For purposes of the following consolidating information, each of SMLP and Summit Holdings account for their subsidiary investments under the equity method of accounting.

Condensed Consolidating Balance Sheets. Balance sheets as of December 31, 2015 and 2014 follow.

	December 31, 2015
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	73	$	12,407	$	6,930	$	2,383	$	—		$	21,793
Accounts receivable	—		—		84,021		5,560		—			89,581
Due from affiliate	3,168		151,443		207,651		—		(362,262		)	—
Other current assets	540		—		2,672		361		—			3,573
Total current assets	3,781		163,850		301,274		8,304		(362,262		)	114,947
Property, plant and equipment, net	1,178		—		1,462,623		348,982		—			1,812,783
Intangible assets, net	—		—		438,093		23,217		—			461,310
Goodwill	—		—		16,211		—		—			16,211
Investment in equity method investees	—		—		—		751,168		—			751,168
Other noncurrent assets	3,480		4,611		162		—		—			8,253
Investment in subsidiaries	2,438,395		3,222,187		—		—		(5,660,582		)	—
Total assets	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672
Liabilities and Partners' Capital
Trade accounts payable	$	482	$	—	$	18,489	$	21,837	$	—		$	40,808
Due to affiliate	360,243		—		—		3,168		(362,262		)	1,149
Deferred revenue	—		—		677		—		—			677
Ad valorem taxes payable	9		—		9,881		381		—			10,271
Accrued interest	—		17,483		—		—		—			17,483
Accrued environmental remediation	—		—		—		7,900		—			7,900
Other current liabilities	4,558		—		7,405		1,334		—			13,297
Total current liabilities	365,292		17,483		36,452		34,620		(362,262		)	91,585
Long-term debt	332,500		934,770		—		—		—			1,267,270
Deferred revenue	—		—		45,486		—		—			45,486
Noncurrent accrued environmental remediation	—		—		—		5,764		—			5,764
Other noncurrent liabilities	1,743		—		5,503		22		—			7,268
Total liabilities	699,535		952,253		87,441		40,406		(362,262		)	1,417,373
Total partners' capital	1,747,299		2,438,395		2,130,922		1,091,265		(5,660,582		)	1,747,299
Total liabilities and partners' capital	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672

EX 99.2-48

EXHIBIT 99.2

	December 31, 2014
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	7,531	$	11,621	$	7,353	$	1,306	$	—		$	27,811
Accounts receivable	—		—		89,201		3,707		—			92,908
Insurance receivable	—		—		—		25,000		—			25,000
Due from affiliate	764		63,239		97,615		—		(161,618		)	—
Other current assets	907		—		2,610		83		—			3,600
Total current assets	9,202		74,860		196,779		30,096		(161,618		)	149,319
Property, plant and equipment, net	1,351		—		1,412,998		208,291		—			1,622,640
Intangible assets, net	—		—		477,734		11,548		—			489,282
Goodwill	—		—		265,062		—		—			265,062
Investment in equity method investees	—		—		—		706,172		—			706,172
Other noncurrent assets	3,771		6,027		189		—		—			9,987
Investment in subsidiaries	2,419,433		3,154,626		—		—		(5,574,059		)	—
Total assets	$	2,433,757	$	3,235,513	$	2,352,762	$	956,107	$	(5,735,677	)	$	3,242,462
Liabilities and Partners' Capital
Trade accounts payable	$	1,144	$	—	$	23,711	$	13,536	$	—		$	38,391
Due to affiliate	163,565		—		—		764		(161,618		)	2,711
Deferred revenue	—		—		2,377		—		—			2,377
Ad valorem taxes payable	23		—		9,095		61		—			9,179
Accrued interest	—		18,858		—		—		—			18,858
Accrued environmental remediation	—		—		—		25,000		—			25,000
Other current liabilities	1,622		15		12,552		1,118		—			15,307
Total current liabilities	166,354		18,873		47,735		40,479		(161,618		)	111,823
Long-term debt	435,000		797,207		—		—		—			1,232,207
Deferred revenue	—		—		55,239		—		—			55,239
Noncurrent accrued environmental remediation	—		—		—		5,000		—			5,000
Other noncurrent liabilities	1,725		—		5,790		—		—			7,515
Total liabilities	603,079		816,080		108,764		45,479		(161,618		)	1,411,784
Total partners' capital	1,830,678		2,419,433		2,243,998		910,628		(5,574,059		)	1,830,678
Total liabilities and partners' capital	$	2,433,757	$	3,235,513	$	2,352,762	$	956,107	$	(5,735,677	)	$	3,242,462

EX 99.2-49

EXHIBIT 99.2

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, 2015, 2014 and 2013 follow.

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	310,830		$	26,989		$	—	$	337,819
Natural gas, NGLs and condensate sales	—			—			42,079			—			—		42,079
Other revenues	—			—			18,411			2,248			—		20,659
Total revenues	—			—			371,320			29,237			—		400,557
Costs and expenses:
Cost of natural gas and NGLs	—			—			31,398			—			—		31,398
Operation and maintenance	—			—			87,286			7,700			—		94,986
General and administrative	—			—			37,926			7,182			—		45,108
Transaction costs	1,342			—			—			—			—		1,342
Depreciation and amortization	603			—			95,586			8,928			—		105,117
Environmental remediation	—			—			—			21,800			—		21,800
Gain on asset sales, net	—			—			(172		)	—			—		(172		)
Long-lived asset impairment	—			—			9,305			—			—		9,305
Goodwill impairment	—			—			248,851			—			—		248,851
Total costs and expenses	1,945			—			510,180			45,610			—		557,735
Other income	2			—			—			—			—		2
Interest expense	(10,494		)	(48,598		)	—			—			—		(59,092		)
Loss before income taxes	(12,437		)	(48,598		)	(138,860		)	(16,373		)	—		(216,268		)
Income tax benefit	603			—			—			—			—		603
Loss from equity method investees	—			—			—			(6,563		)	—		(6,563		)
Equity in earnings of consolidated subsidiaries	(210,394		)	(161,796		)	—			—			372,190		—
Net loss	$	(222,228	)	$	(210,394	)	$	(138,860	)	$	(22,936	)	$	372,190	$	(222,228	)

EX 99.2-50

EXHIBIT 99.2

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	255,211	$	12,267		$	—	$	267,478
Natural gas, NGLs and condensate sales	—			—			97,094		—			—		97,094
Other revenues	—			—			20,398		2,199			—		22,597
Total revenues	—			—			372,703		14,466			—		387,169
Costs and expenses:
Cost of natural gas and NGLs	—			—			72,415		—			—		72,415
Operation and maintenance	—			—			88,927		5,942			—		94,869
General and administrative	—			—			40,447		2,834			—		43,281
Transaction costs	2,985			—			—		—			—		2,985
Depreciation and amortization	588			—			86,762		3,528			—		90,878
Environmental remediation	—			—			—		5,000			—		5,000
Loss on asset sales, net	—			—			442		—			—		442
Long-lived asset impairment	—			—			5,505		—			—		5,505
Goodwill impairment	—			—			54,199		—			—		54,199
Total costs and expenses	3,573			—			348,697		17,304			—		369,574
Other income	—			—			1,189		—			—		1,189
Interest expense	(8,417		)	(40,169		)	—		—			—		(48,586		)
(Loss) income before income taxes	(11,990		)	(40,169		)	25,195		(2,838		)	—		(29,802		)
Income tax (expense) benefit	(1,680		)	—			826		—			—		(854		)
Loss from equity method investees	—			—			—		(16,712		)	—		(16,712		)
Equity in earnings of consolidated subsidiaries	(33,698		)	6,471			—		—			27,227		—
Net (loss) income	$	(47,368	)	$	(33,698	)	$	26,021	$	(19,550	)	$	27,227	$	(47,368	)

EX 99.2-51

EXHIBIT 99.2

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	213,979		$	2,373		$	—		$	216,352
Natural gas, NGLs and condensate sales	—			—			88,185			—			—			88,185
Other revenues	—			—			21,522			101			—			21,623
Total revenues	—			—			323,686			2,474			—			326,160
Costs and expenses:
Cost of natural gas and NGLs	—			—			68,037			—			—			68,037
Operation and maintenance	—			—			77,122			1,053			—			78,175
General and administrative	—			—			33,970			2,746			—			36,716
Transaction costs	2,841			—			—			—						2,841
Depreciation and amortization	454			—			70,122			656			—			71,232
Loss on asset sales, net	—			—			113			—			—			113
Total costs and expenses	3,295			—			249,364			4,455			—			257,114
Other income	5			—			—			—			—			5
Interest expense	(2,141		)	(19,173		)	—			—			—			(21,314		)
(Loss) income before income taxes	(5,431		)	(19,173		)	74,322			(1,981		)	—			47,737
Income tax expense	—			—			(729		)	—			—			(729		)
Equity in earnings of consolidated subsidiaries	52,439			71,612			—			—			(124,051		)	—
Net income (loss)	$	47,008		$	52,439		$	73,593		$	(1,981	)	$	(124,051	)	$	47,008

EX 99.2-52

EXHIBIT 99.2

Condensed Consolidating Statements of Cash Flows. Statements of cash flows for the years ended December 31, 2015, 2014 and 2013 follow.

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	409		$	(46,716	)	$	202,324		$	35,358		$	—	$	191,375
Cash flows from investing activities:
Capital expenditures	(429		)	—			(118,458		)	(153,338		)	—		(272,225		)
Contributions to equity method investees	—			—			—			(86,200		)	—		(86,200		)
Proceeds from asset sales	—			—			323			—			—		323
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618		)	—			—			—			—		(288,618		)
Advances to affiliates	(2,589		)	(88,221		)	(110,003		)	—			200,813		—
Net cash used in investing activities	(291,636		)	(88,221		)	(228,138		)	(239,538		)	200,813		(646,720		)

EX 99.2-53

EXHIBIT 99.2

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(152,074		)	—			—			—		—			(152,074		)
Borrowings under revolving credit facility	180,000			187,000			—			—		—			367,000
Repayments under revolving credit facility	(100,000		)	(51,000		)	—			—		—			(151,000		)
Repayments under term loan	(182,500		)	—			—			—		—			(182,500		)
Deferred loan costs	(135		)	(277		)	—			—		—			(412		)
Proceeds from issuance of common units, net	221,977			—			—			—		—			221,977
Contribution from general partner	4,737			—			—			—		—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	102,500			—			21,719			196,308		—			320,527
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,655			—			3,864			6,360		—			22,879
Other, net	(1,615		)	—			(192		)	—		—			(1,807		)
Advances from affiliates	198,224			—			—			2,589		(200,813		)	—
Net cash provided by financing activities	283,769			135,723			25,391			205,257		(200,813		)	449,327
Net change in cash and cash equivalents	(7,458		)	786			(423		)	1,077		—			(6,018		)
Cash and cash equivalents, beginning of period	7,531			11,621			7,353			1,306		—			27,811
Cash and cash equivalents, end of period	$	73		$	12,407		$	6,930		$	2,383	$	—		$	21,793

EX 99.2-54

EXHIBIT 99.2

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(3,658	)	$	(30,689	)	$	179,685		$	7,615		$	—	$	152,953
Cash flows from investing activities:
Capital expenditures	(460		)	—			(220,360		)	(122,560		)	—		(343,380		)
Initial contribution to Ohio Gathering	—			—			—			(8,360		)	—		(8,360		)
Acquisition of Ohio Gathering Option	—			—			—			(190,000		)	—		(190,000		)
Option Exercise	—			—			—			(382,385		)	—		(382,385		)
Contributions to equity method investees	—			—			—			(145,131		)	—		(145,131		)
Proceeds from asset sales	—			—			325			—			—		325
Acquisition of gathering systems	—			—			(10,872		)	—			—		(10,872		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(305,000		)	—			—			—			—		(305,000		)
Advances to affiliates	(183		)	(174,495		)	(47,271		)	—			221,949		—
Net cash used in investing activities	(305,643		)	(174,495		)	(278,178		)	(848,436		)	221,949		(1,384,803		)

EX 99.2-55

EXHIBIT 99.2

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(122,224		)	—			—			—			—			(122,224		)
Borrowings under revolving credit facility	57,000			237,295			—			—			—			294,295
Repayments under revolving credit facility	(115,000		)	(315,295		)	—			—			—			(430,295		)
Borrowings under term loan	400,000			—			—			—			—			400,000
Repayments under term loan	(100,000		)	—			—			—			—			(100,000		)
Deferred loan costs	(3,003		)	(5,320		)	—			—			—			(8,323		)
Proceeds from issuance of common units, net	197,806			—			—			—			—			197,806
Contribution from general partner	4,235			—			—			—			—			4,235
Cash advance (to) from Summit Investments (from) to contributed subsidiaries, net	(242,000		)	—			81,421			834,962			—			674,383
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,845			—			10,483			1,556			—			24,884
Issuance of senior notes	—			300,000			—			—			—			300,000
Repurchase of equity-based compensation awards	(228		)	—			—			—			—			(228		)
Other, net	(656		)	—			—			—			—			(656		)
Advances from affiliates	221,766			—			—			183			(221,949		)	—
Net cash provided by financing activities	310,541			216,680			91,904			836,701			(221,949		)	1,233,877
Net change in cash and cash equivalents	1,240			11,496			(6,589		)	(4,120		)	—			2,027
Cash and cash equivalents, beginning of period	6,291			125			13,942			5,426			—			25,784
Cash and cash equivalents, end of period	$	7,531		$	11,621		$	7,353		$	1,306		$	—		$	27,811

EX 99.2-56

EXHIBIT 99.2

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by operating activities	$	(544	)	$	(4,799	)	$	141,260		$	(506	)	$	—	$	135,411
Cash flows from investing activities:
Capital expenditures	(930		)	—			(182,048		)	(66,648		)	—		(249,626		)
Proceeds from asset sales	—			—			585			—			—		585
Acquisition of gathering systems	(210,000		)	—			—			—			—		(210,000		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(200,000		)	—			—			—			—		(200,000		)
Advances to affiliates	(84		)	(371,408		)	(36,672		)	—			408,164		—
Net cash used in investing activities	(411,014		)	(371,408		)	(218,135		)	(66,648		)	408,164		(659,041		)

EX 99.2-57

EXHIBIT 99.2

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(90,196		)	—			—		—		—			(90,196		)
Borrowings under revolving credit facility	96,000			380,950			—		—		—			476,950
Repayments under revolving credit facility	(3,000		)	(294,180		)	—		—		—			(297,180		)
Borrowings under term loan	200,000			—			—		—		—			200,000
Repayments under term loan	(100,000		)	—			—		—		—			(100,000		)
Deferred loan costs	(3,451		)	(10,608		)	—		—		—			(14,059		)
Contribution from general partner	2,229			—			—		—		—			2,229
Cash advance (to) from Summit Investments (from) to contributed subsidiaries, net	(193,000		)	—			72,745		70,168		—			(50,087		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	8,088			—			11,964		2,328		—			22,380
Issuance of senior notes	—			300,000			—		—		—			300,000
Repurchase of equity-based compensation awards	(11,957		)	—			—		—		—			(11,957		)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	100,000			—			—		—		—			100,000
Advances from affiliates	408,080			—			—		84		(408,164		)	—
Net cash provided by financing activities	412,793			376,162			84,709		72,580		(408,164		)	538,080
Net change in cash and cash equivalents	1,235			(45		)	7,834		5,426		—			14,450
Cash and cash equivalents, beginning of period	5,056			170			6,108		—		—			11,334
Cash and cash equivalents, end of period	$	6,291		$	125		$	13,942	$	5,426	$	—		$	25,784

EX 99.2-58

EXHIBIT 99.2

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, 2015, follows.

	Quarter ended December 31, 2015			Quarter ended September 30, 2015		Quarter ended June 30, 2015			Quarter ended March 31, 2015
	(In thousands, except per-unit amounts)
Total revenues (1)	$	112,414		$	115,201	$	86,855		$	86,087
Net (loss) income attributable to SMLP (2)(3)	$	(220,468	)	$	23,604	$	2,985		$	1,667
Less net (loss) income attributable to general partner, including IDRs	(2,469		)	2,408		1,891			1,568
Net (loss) income attributable to limited partners	$	(217,999	)	$	21,196	$	1,094		$	99
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.28	)	$	0.32	$	0.05		$	0.00
Common unit – diluted	$	(3.28	)	$	0.32	$	0.05		$	0.00
Subordinated unit – basic and diluted	$	(3.28	)	$	0.32	$	(0.03	)	$	0.00

__________

(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 $7.7 million of long-lived asset impairments.

	Quarter ended December 31, 2014			Quarter ended September 30, 2014		Quarter ended June 30, 2014		Quarter ended March 31, 2014
	(In thousands, except per-unit amounts)
Total revenues (1)	$	114,252		$	94,152	$	93,063	$	85,702
Net (loss) income attributable to SMLP (2)	$	(37,686	)	$	6,113	$	4,036	$	3,545
Less net (loss) income attributable to general partner, including IDRs	689			1,204		801		431
Net (loss) income attributable to limited partners	$	(38,375	)	$	4,909	$	3,235	$	3,114
(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.65	)	$	0.08	$	0.05	$	0.08
Common unit – diluted	$	(0.65	)	$	0.08	$	0.05	$	0.08
Subordinated unit – basic and diluted	$	(0.65	)	$	0.08	$	0.05	$	0.02

__________

(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, 2014, net loss attributable to SMLP includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment.

EX 99.2-59

EXHIBIT 99.2

The amounts for total revenues as originally filed on the respective 2015 and 2014 quarterly reports on Form 10-Q have been retrospectively adjusted for the impact of the 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.

	Quarter ended September 30, 2015		Quarter ended June 30, 2015		Quarter ended March 31, 2015
	(In thousands)
Total revenues as originally reported	$	103,249	$	77,274	$	68,579
2016 Drop Down	8,644		5,911		4,870
Bison revenue reclass	3,308		3,670		4,056
Polar and Divide Drop Down	—		—		8,582
Total revenues	$	115,201	$	86,855	$	86,087

	Quarter ended September 30, 2014		Quarter ended June 30, 2014		Quarter ended March 31, 2014
	(In thousands)
Total revenues as originally reported	$	79,030	$	80,796	$	76,202
2016 Drop Down	4,108		2,414		1,922
Bison revenue reclass	5,260		4,665		4,399
Polar and Divide Drop Down	5,754		5,188		3,179
Total revenues	$	94,152	$	93,063	$	85,702

EX 99.2-60

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Summit Midstream Partners, LP
Entity Central Index Key	0001549922
Document Type	8-K/A
Document Period End Date	Dec. 31, 2015
Amendment Flag	true
Amendment Description	The purpose of this Amendment No. 1 to our Current Report on Form 8-K, originally filed with the Securities and Exchange Commission (“SEC”) on June 6, 2016 (the “Original Filing”), which updated and superseded our Annual Report on Form 10-K dated February 29, 2016 (as updated and superseded by the Original Filing, the "2015 Annual Report"), is to include additional disclosure required in a footnote to our consolidated financial statements under Rule 3-10 of Regulation S-X ("Rule 3-10"). The additional disclosure results from a change in the guarantor structure of the Senior Notes (as defined in Note 9 to the consolidated financial statements) in connection with our March 2016 purchase of an interest in 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 "2016 Drop Down").
Current Fiscal Year End Date	--12-31

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 21,793	$ 27,811
Accounts receivable	89,581	92,908
Insurance receivable	0	25,000
Other current assets	3,573	3,600
Total current assets	114,947	149,319
Property, plant and equipment, net	1,812,783	1,622,640
Intangible assets, net	461,310	489,282
Goodwill	16,211	265,062
Investment in equity method investees	751,168	706,172
Other noncurrent assets	8,253	9,987
Total assets	3,164,672	3,242,462
Current liabilities:
Trade accounts payable	40,808	38,391
Due to affiliate	1,149	2,711
Deferred revenue	677	2,377
Ad valorem taxes payable	10,271	9,179
Accrued interest	17,483	18,858
Accrued environmental remediation	7,900	25,000
Other current liabilities	13,297	15,307
Total current liabilities	91,585	111,823
Long-term debt	1,267,270	1,232,207
Deferred revenue	45,486	55,239
Noncurrent accrued environmental remediation	5,764	5,000
Other noncurrent liabilities	7,268	7,515
Total liabilities	1,417,373	1,411,784
Commitments and contingencies
Common limited partner capital (42,063 units issued and outstanding at December 31, 2015 and 34,427 units issued and outstanding at December 31, 2014)	744,977	649,060
Subordinated limited partner capital (24,410 units issued and outstanding at December 31, 2015 and 2014)	213,631	293,153
General partner interests (1,355 units issued and outstanding at December 31, 2015 and 1,201 units issued and outstanding at December 31, 2014)	25,634	24,676
Summit Investments' equity in contributed subsidiaries	763,057	863,789
Total partners' capital	1,747,299	1,830,678
Total liabilities and partners' capital	$ 3,164,672	$ 3,242,462

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares shares in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common limited partner capital, units issued	42,063	34,427
Common limited partner capital, units outstanding	42,063	34,427
Subordinated limited partner capital, units issued	24,410	24,410
Subordinated limited partner capital, units outstanding	24,410	24,410
General partner interests, units issued	1,355	1,201
General partner interests, units outstanding	1,355	1,201

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Gathering services and related fees	$ 337,819	$ 267,478	$ 216,352
Natural gas, NGLs and condensate sales	42,079	97,094	88,185
Other revenues	20,659	22,597	21,623
Total revenues	400,557	387,169	326,160
Costs and expenses:
Cost of natural gas and NGLs	31,398	72,415	68,037
Operation and maintenance	94,986	94,869	78,175
General and administrative	45,108	43,281	36,716
Transaction costs	1,342	2,985	2,841
Depreciation and amortization	105,117	90,878	71,232
Environmental remediation	21,800	5,000	0
(Gain) loss on asset sales, net	(172)	442	113
Long-lived asset impairment	9,305	5,505	0
Goodwill impairment	248,851	54,199	0
Total costs and expenses	557,735	369,574	257,114
Other income	2	1,189	5
Interest expense	(59,092)	(48,586)	(21,314)
(Loss) income before income taxes	(216,268)	(29,802)	47,737
Income tax benefit (expense)	603	(854)	(729)
Loss from equity method investees	(6,563)	(16,712)	0
Net (loss) income	(222,228)	(47,368)	47,008
Less net income attributable to Summit Investments	(30,016)	(23,376)	3,424
Net (loss) income attributable to SMLP	(192,212)	(23,992)	43,584
Less net (loss) income attributable to general partner, including IDRs	3,398	3,125	1,035
Net (loss) income attributable to limited partners	(195,610)	(27,117)	42,549
Common units
Costs and expenses:
Net (loss) income attributable to limited partners	$ (125,437)	$ (16,324)	$ 23,227
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (3.20)	$ (0.49)	$ 0.86
Diluted (in dollars per share)	$ (3.20)	$ (0.49)	$ 0.86
Weighted-average limited partner units outstanding:
Basic (shares)	39,217	33,311	26,951
Diluted (shares)	39,217	33,311	27,101
Subordinated Units
Costs and expenses:
Net (loss) income attributable to limited partners	$ (70,173)	$ (10,793)	$ 19,322
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (2.88)	$ (0.44)	$ 0.79
Diluted (in dollars per share)	$ (2.88)	$ (0.44)	$ 0.79
Weighted-average limited partner units outstanding:
Basic (shares)	24,410	24,410	24,410
Diluted (shares)	24,410	24,410	24,410

XML

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Bison Midstream	Mountaineer Midstream	Polar Midstream	Drop Down Assets 2016 Acquisition	Class B membership interest	Summit Investments' equity in contributed subsidiaries	Summit Investments' equity in contributed subsidiaries Bison Midstream	Summit Investments' equity in contributed subsidiaries Polar Midstream	Summit Investments' equity in contributed subsidiaries Drop Down Assets 2016 Acquisition	Summit Investments' equity in contributed subsidiaries Class B membership interest	Limited partners, Common	Limited partners, Common Bison Midstream	Limited partners, Common Mountaineer Midstream	Limited partners, Common Class B membership interest	Limited partners, Subordinated	General partner	General partner Bison Midstream	General partner Mountaineer Midstream
Beginning balance at Dec. 31, 2012	$ 1,028,355						$ 209,108					$ 418,856				$ 380,169	$ 20,222
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	47,008						3,424					22,311				20,238	1,035
Distributions to unitholders	(90,196)											(46,286)				(42,107)	(1,803)
Unit-based compensation	2,999					$ 1,243					$ 1,226	2,999			$ 17
Consolidation of net assets		$ 303,168		$ 216,105	$ 21,968			$ 303,168	$ 216,105	$ 21,968
Contributions	2,229						2,229
Purchase of contributed Subsidiaries		$ (200,000)	$ 100,000					$ (248,914)					$ 47,936	$ 98,000				$ 978	$ 2,000
Assets contributed to Red Rock Gathering from Summit Investments	0
Contribution of net assets/excess of acquired carrying value over consideration paid	56,535						(56,535)					28,558				26,846	1,131
Cash advance from Summit Investments to contributed subsidiaries, net	(50,087)						(50,087)
Capitalized interest allocated to contributed subsidiaries from Summit Investments	2,539						2,539
Capitalized interest allocated to contributed subsidiaries from Summit Investments	22,380						22,380
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	52						52
Repurchase of DFW Net Profits Interests and SMLP LTIP units	(11,957)											(5,859)				(5,859)	(239)
Ending balance at Dec. 31, 2013	1,395,806						426,663					566,532				379,287	23,324
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	(47,368)						(23,376)					(15,948)				(11,169)	3,125
Distributions to unitholders	(122,224)											(67,658)				(49,796)	(4,770)
Unit-based compensation	4,696					1,145					1,145	4,696
Tax withholdings on vested SMLP LTIP awards	(656)											(656)
Issuance of common units, net of offering costs	197,806											197,806
Contributions	4,235																4,235
Purchase of contributed Subsidiaries	(307,941)						(307,941)
Excess of purchase price over acquired carrying value of Red Rock Gathering							(66,124)					37,910				26,891	1,323
Assets contributed to Red Rock Gathering from Summit Investments	4,233											2,426				1,722	85
Contribution of net assets/excess of acquired carrying value over consideration paid	0
Cash advance from Summit Investments to contributed subsidiaries, net	674,383						674,383
Capitalized interest allocated to contributed subsidiaries from Summit Investments	1,310						1,310
Capitalized interest allocated to contributed subsidiaries from Summit Investments	24,884						24,884
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	597						597
Repurchase of DFW Net Profits Interests and SMLP LTIP units	(228)											228
Ending balance at Dec. 31, 2014	1,830,678						863,789					649,060				293,153	24,676
Increase (Decrease) in Partners' Capital [Roll Forward]
Net (loss) income	(222,228)						(30,016)					(123,817)				(71,793)	3,398
Distributions to unitholders	(152,074)											(86,880)				(55,410)	(9,784)
Unit-based compensation	6,174					$ 843					$ 843	6,174
Tax withholdings on vested SMLP LTIP awards	(1,616)											(1,616)
Issuance of common units, net of offering costs	221,977											221,977
Contributions	4,737																4,737
Purchase of contributed Subsidiaries	(285,677)						(285,677)
Assets contributed to Red Rock Gathering from Summit Investments	0
Contribution of net assets/excess of acquired carrying value over consideration paid	0						(130,367)					80,079				47,681	2,607
Cash advance from Summit Investments to contributed subsidiaries, net	320,527						320,527
Capitalized interest allocated to contributed subsidiaries from Summit Investments	1,079						1,079
Capitalized interest allocated to contributed subsidiaries from Summit Investments	22,879						22,879
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	0
Ending balance at Dec. 31, 2015	$ 1,747,299						$ 763,057					$ 744,977				$ 213,631	$ 25,634

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net (loss) income	$ (222,228)	$ (47,368)	$ 47,008
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	105,903	91,822	72,264
Amortization of deferred loan costs	4,309	3,836	2,757
Unit-based and noncash compensation	7,017	5,841	4,242
Loss from equity method investees	6,563	16,712	0
Distributions from equity method investees	34,641	2,992	0
(Gain) loss on asset sales, net	(172)	442	113
Long-lived asset impairment	9,305	5,505	0
Goodwill impairment	248,851	54,199	0
Write-off of debt issuance costs	727	1,554	0
Purchase accounting adjustment	0	(1,185)	0
Changes in operating assets and liabilities:
Accounts receivable	3,328	(21,503)	(21,950)
Insurance receivable	25,000	(25,000)	0
Trade accounts payable	(1,450)	(420)	1,427
Due to affiliate	1,377	(883)	(6,153)
Change in deferred revenue	(11,453)	26,378	16,685
Ad valorem taxes payable	1,092	804	(11)
Accrued interest	(1,375)	6,714	12,128
Accrued environmental remediation, net	(16,336)	30,000	0
Other, net	(3,724)	2,513	6,901
Net cash provided by operating activities	191,375	152,953	135,411
Cash flows from investing activities:
Capital expenditures	(272,225)	(343,380)	(249,626)
Initial contribution to Ohio Gathering	0	(8,360)	0
Acquisition of Ohio Gathering Option	0	(190,000)	0
Option Exercise	0	(382,385)	0
Contributions to equity method investees	(86,200)	(145,131)	0
Proceeds from asset sales	323	325	585
Acquisition of gathering systems	0	(10,872)	(210,000)
Acquisitions of gathering systems from affiliate	(288,618)	(305,000)	(200,000)
Net cash used in investing activities	(646,720)	(1,384,803)	(659,041)
Cash flows from financing activities:
Distributions to unitholders	(152,074)	(122,224)	(90,196)
Borrowings under revolving credit facility	367,000	294,295	476,950
Repayments under revolving credit facility	(151,000)	(430,295)	(297,180)
Borrowings under term loan	0	400,000	200,000
Repayments under term loan	(182,500)	(100,000)	(100,000)
Deferred loan costs	(412)	(8,323)	(14,059)
Proceeds from issuance of common units, net	221,977	197,806	0
Contribution from general partner	4,737	4,235	2,229
Cash advance from (to) Summit Investments to (from) contributed subsidiaries, net	320,527	674,383	(50,087)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	22,879	24,884	22,380
Issuance of senior notes	0	300,000	300,000
Repurchase of equity-based compensation awards	0	(228)	(11,957)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	0	0	100,000
Other, net	(1,807)	(656)	0
Net cash provided by financing activities	449,327	1,233,877	538,080
Net change in cash and cash equivalents	(6,018)	2,027	14,450
Cash and cash equivalents, beginning of period	27,811	25,784	11,334
Cash and cash equivalents, end of period	21,793	27,811	25,784
Supplemental cash flow disclosures:
Cash interest paid	59,302	38,453	13,170
Less capitalized interest	3,372	4,646	6,690
Interest paid (net of capitalized interest)	55,930	33,807	6,480
Cash paid for taxes	0	0	660
Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	34,977	31,110	30,528
Excess of acquired carrying value over consideration paid for Polar and Divide	130,367	0	0
Capitalized interest allocated to contributed subsidiaries from Summit Investments	1,079	1,310	2,539
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	0	597	52
Excess of consideration paid over acquired carrying value of Red Rock Gathering	0	(66,124)	0
Assets contributed to Red Rock Gathering from Summit Investments	0	4,233	0
Issuance of units to affiliate to partially fund the Bison Drop Down	0	0	48,914
Contribution of net assets from Summit Investments in excess of consideration paid for Bison Midstream	$ 0	$ 0	$ 56,535

XML

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, was formed in May 2012 and began operations in October 2012 in connection with its initial public offering ("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 Midstream Holdings, LLC ("Summit Holdings"), a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

Summit Midstream GP, LLC (the "general partner"), a Delaware limited liability company, manages our operations and activities. Summit Midstream Partners, LLC ("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 II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners").

In addition to its 2% general partner interest in SMLP (including the incentive distribution rights ("IDRs") in respect of SMLP), Summit Investments has direct and indirect ownership interests in our common and subordinated units. As of December 31, 2015, Summit Investments beneficially owned 5,444,731 SMLP common units and all of our subordinated 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 Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River" or the "Legacy Grand River" system).

On June 4, 2013, the Partnership acquired all of the membership interests of Bison Midstream, LLC ("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. Prior to the Bison Drop Down, on February 15, 2013, Summit Investments acquired Bear Tracker Energy, LLC ("BTE"), which was subsequently renamed Meadowlark Midstream Company, LLC ("Meadowlark Midstream"). 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.

On June 21, 2013, Mountaineer Midstream Company, LLC ("Mountaineer Midstream"), 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. ("MarkWest") (the "Mountaineer Acquisition"). In December 2013, Mountaineer Midstream was merged into DFW Midstream.

On March 18, 2014, SMLP acquired all of the membership interests of Red Rock Gathering Company, LLC ("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.

On May 18, 2015, the Partnership acquired all of the membership interests of Polar Midstream, LLC ("Polar Midstream") and Epping Transmission Company, LLC ("Epping," and collectively with Polar Midstream, "Polar and Divide") 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.

On February 25, 2016, the Partnership and Summit Midstream Partners Holdings, LLC (“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 Summit Midstream OpCo, LP ("OpCo"), a Delaware limited partnership that owns (i) 100% of the issued and outstanding membership interests of Summit Midstream Utica, LLC ("Summit Utica"), Meadowlark Midstream Company, LLC ("Meadowlark Midstream") and Tioga Midstream, LLC ("Tioga Midstream" and collectively with Summit Utica and Meadowlark Midstream, the "Contributed Entities"), each a limited liability company and (ii) a 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively with OpCo and the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down closed on March 3, 2016. Subsequent to closing, SMP Holdings retained a 1.0% noncontrolling interest in OpCo, which is managed by Summit Midstream OpCo GP, LLC ("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. Our gathering systems and the unconventional resource basins in which they operate are as follows:

• Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

• Bison Midstream, an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Polar and Divide, crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Tioga Midstream, crude oil, produced water and associated natural gas gathering systems, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Grand River, a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah;

• Niobrara Gathering and Processing ("Niobrara G&P"), an associated natural gas gathering and processing system operating in the Denver-Julesburg ("DJ") Basin, which includes the Niobrara shale formation in northeastern Colorado;

• DFW Midstream, a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

• Mountaineer Midstream gathering system ("Mountaineer Midstream"), a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

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.

Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively, "Ohio Gathering") operate a natural gas gathering system and a condensate stabilization facility in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio.

Presentation and Consolidation. We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board (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.

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) DFW Midstream and Grand River for all periods presented, (ii) Bison Midstream, Polar and Divide and Niobrara G&P since February 2013, (iii) Mountaineer Midstream since June 2013, (iv) Ohio Gathering since January 2014, (v) Tioga Midstream since April 2014 and (vi) Summit Utica since December 2014. The financial position, results of operations and cash flows of Bison Midstream, 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 purchase price 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. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. We combined the balances associated with the unfavorable gas gathering contract with other noncurrent liabilities. These balance sheet changes had no impact on (i) total liabilities or (ii) total liabilities and partners' capital.

We also evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts and (ii) certain pass-through expenses also for Bison Midstream. As a result of this evaluation, we determined that certain amounts that had previously been recognized in cost of natural gas and NGLs would be more appropriately reflected as gathering services and related fees and other revenues to enhance reporting transparency. The impact of these reclassifications, which had no impact on net (loss) income, total partners' capital or segment adjusted EBITDA, follows.

	Year ended December 31,
	2014		2013
	(In thousands)
Gathering services and related fees	$	15,616	$	16,805
Other revenues	3,952		10,068
Net impact on total revenues	$	19,568	$	26,873
Cost of natural gas and NGLs	$	19,568	$	26,873
Net impact on cost of natural gas and NGLs and total costs and expenses	$	19,568	$	26,873

In the fourth quarter 2015, we began reporting all of our operations in North Dakota as one reportable segment, the Williston Basin reportable segment. This presentation change had no impact on total assets, total liabilities, total revenues, total costs and expenses, net income, partners' capital, cash flows or total segment adjusted EBITDA. See Note 3 for additional information on this change.

In the first quarter of 2016, we adopted Accounting Standards Update ("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 deferred loan costs from other noncurrent assets to long-term debt at December 31, 2015 and $10.8 million at December 31, 2014 (see Note 2).

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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.

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.

	Useful lives (In years)
Gathering and processing systems and related equipment	30
Other	4-15

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, 2015 or 2014.

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 on a units-of-production basis 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.

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 deferred loan costs over the life of the revolving credit facility. We recognize amortization of deferred loan costs in interest expense.

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 our DFW Midstream customers and our procurement of electricity to operate DFW Midstream's electric-drive compression assets. Our gas gathering agreements with our 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 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 also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas 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:

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

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

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

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.

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 our 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 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:

• Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, and/or processing and (ii) crude oil and/or produced water gathering.

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

Certain of our gathering and processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("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 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 statement of operations over the vesting period of the respective awards.

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.

In 2014, we elected to apply changes to the determination of cost of goods sold for the Texas Margin Tax which permits the use of accelerated depreciation allowed for federal income tax purposes.  As a result of this change, we recognized a deferred tax liability. Other noncurrent liabilities included a deferred tax liability of $0.6 million and $1.6 million as of December 31, 2015 and 2014, respectively.

Earnings or Loss Per Unit ("EPU"). 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) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (ii) the general partner's 2% interest in net income or loss and (iii) 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 receipt is deemed probable.

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.

Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with debt incurred by SMP or its affiliates which was replaced with bank borrowings or debt capital at the Partnership, we allocate a portion of that debt, net of deferred loan 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. There are currently no recent pronouncements that have been issued that we believe may materially affect our financial statements, except as noted below.

In May 2014, the FASB released a joint revenue recognition standard, ASU No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) the Company satisfies a performance obligation. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted.  In July 2015, the FASB reaffirmed the guidance in its April 2015 proposed ASU that defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We are currently in the process of evaluating the impact of this update.

In April 2015, the FASB issued ASU 2015-03. Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. This presentation will result in debt issuance cost being presented the same way debt discounts have historically been handled. In August 2015, the FASB amended ASU 2015-03 to address the presentation and subsequent measurement of debt issuance costs related to line of credit (“LOC”) arrangements. The amendment added a paragraph that states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of a LOC arrangement, regardless of whether there are outstanding borrowings under that LOC arrangement.  This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter.  Early adoption is permitted. The adoption of this update has resulted in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes. Debt issuance costs associated with our revolving credit facility will remain in other noncurrent assets. This ASU had no impact on interest expense, net income or loss, EPU or partners' capital.

In September 2015, the FASB issued ASU No. 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). Under ASU 2015-16, an acquirer would be required to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the acquirer must record in the financial statements for the same period, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Entities must also present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter.  Early adoption is permitted. We are currently in the process of evaluating the impact of this update.

In January 2016, the FASB issued ASU No. 2016-01 Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Among other changes, the amendments in ASU 2016-01 supersede the guidance to classify equity securities with readily determinable fair values into different categories and require equity securities to be measured at fair value with changes in the fair value recognized through net income. They also simplify the impairment assessment of equity investments without readily determinable fair values and require use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes. Under ASU 2016-01, an entity will be required to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, to separately present financial assets and financial liabilities by measurement category and form of financial asset. ASU 2016-01 also clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 31, 2017. Early adoption is permissible, but limited in application. The adoption of this new update could impact the fair value we disclose for certain financial instruments but is not expected to impact amounts recognized in the consolidated financial statements.

XML

SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

As of December 31, 2015, our reportable segments are:

• the Utica Shale, which includes our ownership interest in Ohio Gathering and also is served by Summit Utica;

• the Williston Basin, which is served by Bison Midstream, Polar and Divide and Tioga Midstream;

• the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;

• the Barnett Shale, which is served by DFW Midstream; and

• the Marcellus Shale, which is served by Mountaineer Midstream.

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, our investment in Ohio Gathering is included in the Utica Shale reportable segment. Segment assets for the Utica Shale includes the associated investment in equity method investees. 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.

In connection with the Polar and Divide Drop Down, we identified two reportable segments in the Williston Basin. For the second and third quarters of 2015, we reported the results of Bison Midstream in the Williston Basin – Gas reportable segment and those of Polar and Divide in the Williston Basin – Liquids reportable segment. In the fourth quarter of 2015, we changed how we manage and evaluate our operations in North Dakota. Prior to the fourth quarter of 2015, Bison Midstream and Polar and Divide were managed separately and their financial results were evaluated separately. In the fourth quarter of 2015, we began managing our North Dakota operations under a single management team and began reporting their financial results on a combined basis. As a result, we no longer distinguish between liquids and gas in the Williston Basin and now have one reportable segment, the Williston Basin reportable segment, representing those operations.

Corporate represents those assets and liabilities and revenues and expenses that are not specifically attributable to a reportable segment, not individually reportable, or that have not been allocated to our reportable segments. Beginning in the first quarter of 2015, we discontinued allocating certain general and administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.

Assets by reportable segment follow.

	December 31,
	2015		2014		2013
	(In thousands)
Assets:
Utica Shale (1)	$	886,224	$	735,587	$	—
Williston Basin	740,361		861,461		680,014
Piceance/DJ Basins	866,095		941,382		936,794
Barnett Shale	416,586		428,935		431,578
Marcellus Shale	233,116		243,884		214,379
Total reportable segment assets	3,142,382		3,211,249		2,262,765
Corporate	22,290		31,213		19,281
Total assets	$	3,164,672	$	3,242,462	$	2,282,046

__________

(1) Represents the investment in equity method investees for Ohio Gathering (see Note 7) and total assets for Summit Utica.

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.

Revenues by reportable segment follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Revenues:
Utica Shale	$	4,700	$	190	$	—
Williston Basin	98,929		109,807		81,501
Piceance/DJ Basins	180,418		161,477		129,747
Barnett Shale	88,042		93,001		105,324
Marcellus Shale	28,468		22,694		9,588
Total reportable segment revenues and total revenues	$	400,557	$	387,169	$	326,160

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

	Year ended December 31,
	2015		2014		2013
Percentage of total revenues (1):
Counterparty A - Piceance/DJ Basins	16	%	18	%	19	%
Counterparty B - Piceance/DJ Basins	14	%	*		*
Counterparty C - Barnett Shale	*		*		14	%

__________

(1) Includes recognition of revenue that was previously deferred in connection with minimum volume commitments (see Notes 2 and 8).

* Less than 10%

Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Depreciation and amortization:
Utica Shale	$	1,417	$	—	$	—
Williston Basin	31,376		24,027		16,669
Piceance/DJ Basins	47,433		42,959		36,185
Barnett Shale	16,392		16,601		14,961
Marcellus Shale	8,682		7,648		3,998
Total reportable segment depreciation and amortization	105,300		91,235		71,813
Corporate	603		587		451
Total depreciation and amortization	$	105,903	$	91,822	$	72,264

Capital expenditures by reportable segment follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Capital expenditures:
Utica Shale	$	94,994	$	24,787	$	—
Williston Basin	147,477		227,283		129,236
Piceance/DJ Basins	21,144		42,417		88,104
Barnett Shale	6,875		14,567		29,534
Marcellus Shale	1,306		33,866		1,822
Total reportable segment capital expenditures	271,796		342,920		248,696
Corporate	429		460		930
Total capital expenditures	$	272,225	$	343,380	$	249,626

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) impairments and (vi) 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 total revenues less total expenses, plus amortization for deferred contract costs multiplied by our ownership interest in Ohio Gathering during the respective period.

Segment adjusted EBITDA by reportable segment follows.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	35,873	$	6,176	$	—
Williston Basin	34,008		30,009		17,350
Piceance/DJ Basins	110,222		110,763		79,687
Barnett Shale	59,526		60,528		69,473
Marcellus Shale	23,214		15,940		6,333
Total reportable segment adjusted EBITDA	$	262,843	$	223,416	$	172,843

__________

(1) Includes our proportional share of adjusted EBITDA for Ohio Gathering and is reflected as the proportional adjusted EBITDA for equity method investees in the reconciliation of income or loss before income taxes to segment adjusted EBITDA.

A reconciliation of (loss) income before income taxes to total reportable segment adjusted EBITDA follows.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Reconciliation of income (loss) before income taxes to segment adjusted EBITDA:
(Loss) income before income taxes	$	(216,268	)	$	(29,802	)	$	47,737
Add:
Allocated corporate expenses	27,352			15,441			10,153
Interest expense	59,092			48,586			21,314
Depreciation and amortization	105,903			91,822			72,264
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based and noncash compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
Interest income	2			4			5
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Total reportable segment adjusted EBITDA	$	262,843		$	223,416		$	172,843

Segment adjusted EBITDA excludes the effect of allocated corporate expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, interest expense and income tax expense.

Adjustments related to MVC shortfall payments account for:

• the net increases or decreases in deferred revenue for MVC shortfall payments and

• our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our consolidated financial statements.

Adjustments related to MVC shortfall payments by reportable segment follow.

	Year ended December 31,
	2015			2014		2013
	(In thousands)
Adjustments related to MVC shortfall payments:
Williston Basin	$	11,870		$	10,743	$	3,600
Piceance/DJ Basins	(21,590		)	15,194		12,395
Barnett Shale	(2,182		)	628		1,030
Total adjustments related to MVC shortfall payments	$	(11,902	)	$	26,565	$	17,025

XML

PROPERTY, PLANT, AND EQUIPMENT, NET

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT, AND EQUIPMENT, NET

PROPERTY, PLANT, AND EQUIPMENT, NET

Details on property, plant, and equipment follow.

	December 31,
	2015		2014
	(In thousands)
Gathering and processing systems and related equipment	$	1,883,139	$	1,630,250
Construction in progress	75,132		48,500
Land and line fill	11,055		11,057
Other	32,427		58,375
Total	2,001,753		1,748,182
Less accumulated depreciation	188,970		125,542
Property, plant, and equipment, net	$	1,812,783	$	1,622,640

During 2015 and 2014, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired. (There were no impairment indicators during 2013.) 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.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Long-lived asset impairment:
Williston Basin	$	7,554	$	—	$	—
Barnett Shale	531		5,505		—
Piceance/DJ Basins	1,220		—		—

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.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Depreciation expense	$	63,915	$	53,064	$	37,947
Capitalized interest	3,372		4,646		6,690

XML

AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

AMORTIZING INTANGIBLE ASSETS AND LIABILITIES AND UNFAVORABLE GAS GATHERING CONTRACT

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.

	December 31, 2015
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(9,534	)	$	14,661
Contract intangibles	12.5	426,464		(111,052		)	315,412
Rights-of-way	26.3	150,143		(18,906		)	131,237
Total intangible assets		$	600,802	$	(139,492	)	$	461,310
Unfavorable gas gathering contract	10.0	$	10,962	$	(6,077	)	$	4,885

	December 31, 2014
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(8,056	)	$	16,139
Contract intangibles	12.5	426,464		(75,713		)	350,751
Rights-of-way	27.0	135,435		(13,043		)	122,392
Total intangible assets		$	586,094	$	(96,812	)	$	489,282
Unfavorable gas gathering contract	10.0	$	10,962	$	(5,385	)	$	5,577

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.

We recognized amortization expense in other revenues as follows:

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(1,478	)	$	(1,741	)	$	(2,078	)
Amortization expense – unfavorable gas gathering contract	692			797			1,046

We recognized amortization expense in costs and expenses as follows:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Amortization expense – contract intangibles	$	35,339	$	32,554	$	28,654
Amortization expense – rights-of-way	5,863		5,260		4,631

The estimated aggregate annual amortization expected to be recognized as of December 31, 2015 for each of the five succeeding fiscal years follows.

	Intangible assets		Unfavorable gas gathering contract
	(In thousands)
2016	$	43,108	$	924
2017	41,959		1,047
2018	41,413		1,035
2019	41,659		1,045
2020	44,305		834

XML

GOODWILL

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

GOODWILL

Recorded 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.

	Piceance/DJ Basins			Williston Basin			Marcellus Shale		Total
	(In thousands)
Goodwill, January 1, 2014	$	45,478		$	257,572		$	16,211	$	319,261
Goodwill impairment	—			(54,199		)	—		(54,199		)
Goodwill, December 31, 2014	45,478			203,373			16,211		265,062
Goodwill impairment	(45,478		)	(203,373		)	—		(248,851		)
Goodwill, December 31, 2015	$	—		$	—		$	16,211	$	16,211

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

	December 31,
	2015		2014		2013
	(In thousands)
Accumulated goodwill impairment:
Piceance/DJ Basins	$	45,478	$	—	$	—
Williston Basin	257,572		54,199		—
Total accumulated goodwill impairment	$	303,050	$	54,199	$	—

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.

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.

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.

Our preliminary estimates of the fair values of the identified assets and liabilities calculated in step two indicated that all of the associated goodwill for both reporting units had been impaired. As such, we recorded an estimated goodwill impairment of $45.5 million for Grand River and $203.4 million for Polar and Divide. These amounts represent our estimate of impairment pending finalization of the fair value calculations. We expect finalization to occur in the first quarter of 2016.

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.

XML

EQUITY METHOD INVESTMENTS

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INVESTMENTS

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 1.0% 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 1.0% ownership interest.

The ownership interest Summit Investments acquired from Blackhawk included an option to increase the holder's ownership interest in Ohio Gathering to 40.0% (the "Option"). In May 2014, Summit Investments exercised the Option to increase its ownership to 40.0% (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 40.0% 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 60.0% 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 40.0% 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.

A rollforward of the investment in equity method investees follows.

	2015			2014
	(In thousands)
Investment in equity method investees, January 1	$	706,172		$	—
Cash contributions	86,200			145,131
Cash distributions	(34,641		)	(2,992		)
Gain (loss) from equity method investees	6,790			(4,472		)
Amortization of basis difference in equity method investees	(13,353		)	(12,240		)
Acquisition of initial interest in Ohio Gathering	—			190,000
January 2014 initial cash contribution	—			8,360
Option Exercise	—			382,385
Investment in equity method investees, December 31	751,168			706,172
December cash distributions	3,472			—
December cash contributions	—			(20,420		)
Basis difference	(156,888		)	(170,241		)
Investment in equity method investees, net of basis difference, November 30	$	597,752		$	515,511

The following table presents summarized balance sheet information for Ohio Gathering.

	November 30,
	2015		2014
	(In thousands)
Total assets	$	1,510,075	$	1,341,007
Total liabilities	59,313		95,391
Members' equity	1,450,762		1,245,616

The following table presents summarized statements of operations information for Ohio Gathering for the twelve months ended November 30, 2015 and for the period of ownership in 2014.

	Twelve months ended November 30, 2015		Ten months ended November 30, 2014
	(In thousands)
Total revenues	$	130,090	$	45,313
Total operating expenses	112,581		66,374
Net income (loss)	16,803		(21,061		)

XML

DEFERRED REVENUE

12 Months Ended

Dec. 31, 2015

Deferred Revenue Disclosure [Abstract]

Deferred Revenue

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:

• To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of that customer's MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable).

• To the extent that a customer's throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply will be less than the weighted-average of the original stated contract terms of our MVCs.

• To the extent that certain of our customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.

A rollforward of current deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2014	$	—	$	—	$	1,555	$	1,555
Additions	—		—		2,610		2,610
Less revenue recognized	—		—		1,788		1,788
Current deferred revenue, December 31, 2014	—		—		2,377		2,377
Additions	—		2,743		677		3,420
Less revenue recognized	—		2,743		2,377		5,120
Current deferred revenue, December 31, 2015	$	—	$	—	$	677	$	677

A rollforward of noncurrent deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2014	$	6,389	$	23,294	$	—	$	29,683
Additions	10,743		14,813		—		25,556
Noncurrent deferred revenue, December 31, 2014	17,132		38,107		—		55,239
Additions	11,897		12,765		—		24,662
Less revenue recognized	27		34,388		—		34,415
Noncurrent deferred revenue, December 31, 2015	$	29,002	$	16,484	$	—	$	45,486

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 area of mutual interest ("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, 2015, accounts receivable included $12.7 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods.

XML

DEBT

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

DEBT

DEBT

Debt consisted of the following:

	December 31,
	2015			2014
	(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (2.93% at December 31, 2015 and 2.67% at December 31, 2014) due November 2018	$	344,000		$	208,000
Summit Holdings 5.50% Senior unsecured notes due August 2022	300,000			300,000
Less unamortized deferred loan costs (1)	(4,139		)	(4,773		)
Summit Holdings 7.50% Senior unsecured notes due July 2021	300,000			300,000
Less unamortized deferred loan costs (1)	(5,091		)	(6,020		)
SMP Holdings variable rate senior secured revolving credit facility (2.43% at December 31, 2015 and 2.17% at December 31, 2014) due February 2019 (2)	115,000			35,000
SMP Holdings variable rate senior secured term loan (2.43% at December 31, 2015 and 2.17% at December 31, 2014) due May 2017 (2)	217,500			400,000
Total long-term debt	$	1,267,270		$	1,232,207

__________

(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 Initial Close.

The aggregate amount of debt maturing during each of the years after December 31, 2015 are as follows:

	Debt
	(In thousands)
2016	$	—
2017 (1)	217,500
2018	344,000
2019 (1)	115,000
2020	—
Thereafter	600,000
Total long-term debt	$	1,276,500

__________

(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 Initial Close.

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"). The revolving credit facility has a $700.0 million borrowing capacity, matures in November 2018, and includes a $200.0 million accordion feature.

Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("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, 2015, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 2.93% and the unused portion of the revolving credit facility totaled $356.0 million (subject to a commitment fee of 0.50%).

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.

On February 25, 2016, we closed on an amendment to the revolving credit facility, which became effective concurrent with the March 3, 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 5.50 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.

As of December 31, 2015, 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, 2015.

Guarantees at December 31, 2015. As of December 31, 2015, the revolving credit facility was secured by the membership interests of Summit Holdings and those of its subsidiaries and substantially all of Summit Holdings' and its then-subsidiaries' assets were pledged as collateral under the revolving credit facility. Additionally, the revolving credit facility, and Summit Holdings' obligations, were guaranteed by SMLP and each of its subsidiaries.

Guarantee Subsequent Event. Following the 2016 Drop Down in March 2016, OpCo GP, OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream became 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 which removed the guarantees of OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream ("Non-Guarantor Subsidiaries"). Following execution of the consent and waiver agreement, the Guarantor Subsidiaries group included Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream Services and OpCo GP. For additional information, see Note 17.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes" and together with the 5.5% senior notes, the "Senior Notes").

Guarantees at December 31, 2015. As of December 31, 2015, Bison Midstream and its subsidiaries, Grand River and its subsidiary and DFW Midstream Services (collectively, the "Guarantor Subsidiaries") and SMLP have fully and unconditionally and jointly and severally guaranteed the Senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility and the Senior Notes. Finance Corp. has no assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan.

Guarantee Subsequent Event. As noted above, a consent and waiver agreement was executed in August 2016 with an effective date of March 30, 2016 which removed the guarantees of Non-Guarantor Subsidiaries from the Senior Notes. Following execution of the consent and waiver agreement, the Senior Notes are guaranteed by SMLP, Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream Services and OpCo GP.

5.5% Senior Notes. We will pay interest on the 5.5% senior notes semi-annually in cash in arrears on February 15 and August 15 of each year, commencing February 15, 2015. The 5.5% senior notes are senior, unsecured obligations and rank equally in right of 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, 2015, 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, 2015.

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 of 1933, as amended (the "Securities Act"), and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act.

We pay interest on the 7.5% senior notes semi-annually in cash in arrears on January 1 and July 1 of each year. The 7.5% senior notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 7.5% 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 7.5% senior notes to repay a portion of the balance outstanding under our revolving credit facility.

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 are 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 do not apply to the registered senior notes.

At any time prior to July 1, 2016, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 7.5% senior notes at a redemption price of 107.500% of the principal amount of the 7.5% 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 July 1, 2016, the Co-Issuers may 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. Debt issuance costs of $7.4 million are being amortized over the life of the senior notes.

The 7.5% 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 7.5% 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 7.5% senior notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 7.5% 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 7.5% 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 7.5% 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 7.5% senior notes may declare all the 7.5% senior notes to be due and payable immediately.

As of December 31, 2015, 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, 2015.

SMP Holdings Credit Facility. In March 2013, SMP Holdings closed on a $150.0 million senior secured revolving credit facility (the "SMP Revolving Credit Facility") and a $200.0 million senior secured term loan (the "Term Loan" and, collectively with the SMP Revolving Credit Facility, the "SMP Holdings Credit Facility"). Borrowings under the SMP Holdings Credit Facility incurred interest at LIBOR or a base rate (as defined in the SMP Holdings Credit Facility) plus an applicable margin. Because the funding 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 years ended December 31, 2015, 2014 and 2013.

In February 2014, SMP Holdings closed on an amendment and restatement of the SMP Holdings Credit Facility whereby it:

(i) increased the borrowing capacity from $150.0 million to $250.0 million;

(ii) extended the maturity date from March 2018 to February 2019;

(iii) added a $100.0 million revolving credit facility accordion feature and a $400.0 million term loan accordion;

(iv) reduced the leverage-based pricing grid by 0.75% from a range of 2.75% to 3.75% to a new range of 2.00% to 3.00% for LIBOR borrowings and from a range of 1.75% to 2.75% to a new range of 1.00% to 2.00% for alternate base rate borrowings;

(v) changed the commitment fee from 0.50% to a leverage-based range of 0.30% to 0.50%; and

(vi) increased the maximum total leverage ratio from 4.0 to 1.0 to 5.0 to 1.0 and from not more than 5.0 to 1.0 to 5.5 to 1.0 for up to 270 days following certain acquisitions, or material projects or, at its option, after a qualified notes offering (as defined in the SMP Holdings Credit Facility).

In March 2014, Summit Investments used the proceeds from its offering of SMLP common units to repay the remaining $100.0 million balance on the then-outstanding Term Loan as well as $95.0 million then outstanding under the SMP Revolving Credit Facility. It wrote off $1.5 million of deferred loan costs in connection with these repayments. In May 2014, Summit Investments borrowed $400.0 million pursuant to the Term Loan accordion (the "Incremental Term Loan"). In May 2015, it repaid $175.0 million of the Incremental Term Loan and wrote off $0.7 million of deferred loan costs in connection therewith.

On March 3, 2016, the remaining balances on the SMP Revolving Credit Facility and the Incremental Term Loan were repaid in full and the SMP Holdings Credit Facility was terminated concurrent with the closing of the 2016 Drop Down (see Note 16).

The SMP Holdings Credit Facility contained affirmative and negative covenants customary for credit facilities of its size and nature. As of December 31, 2015, Summit Investments was in compliance with the covenants in the SMP Holdings Credit Facility. There were no defaults or events of default during the year ended December 31, 2015 or during the period from December 31, 2015 to the March 3, 2016 termination of the SMP Holdings Credit Facility.

XML

FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

FINANCIAL INSTRUMENTS

FINANCIAL INSTRUMENTS

Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and accounts receivable. We maintain our cash 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 68% of total accounts receivable at December 31, 2015, compared with 57% as of December 31, 2014.

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

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

	December 31, 2015				December 31, 2014
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings revolving credit facility	$	344,000	$	344,000	$	208,000	$	208,000
Summit Holdings 5.5% senior notes ($300.0 million principal)	295,861		224,000		295,227		281,750
Summit Holdings 7.5% senior notes ($300.0 million principal)	294,909		257,000		293,980		306,750
SMP Holdings revolving credit facility (1)	115,000		115,000		35,000		35,000
SMP Holdings term loan (1)	217,500		217,500		400,000		400,000

__________

(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 Initial 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, 2015 and December 31, 2014. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

XML

PARTNERS' CAPITAL

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

PARTNERS' CAPITAL

PARTNERS' CAPITAL

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

	Common	Subordinated	General partner	Total
Units, January 1, 2013	24,412,427	24,409,850	996,320	49,818,597
Units issued to a subsidiary of Summit Investments in connection with the Bison Drop Down	1,553,849	—	31,711	1,585,560
Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition	3,107,698	—	63,422	3,171,120
Net units issued under SMLP LTIP	5,892	—	—	5,892
Units, January 1, 2014	29,079,866	24,409,850	1,091,453	54,581,169
Units issued in connection with the March Equity 2014 Offering	5,300,000	—	108,337	5,408,337
Net units issued under SMLP LTIP	46,647	—	861	47,508
Units, December 31, 2014	34,426,513	24,409,850	1,200,651	60,037,014
Units issued in connection with the May 2015 Equity Offering	7,475,000	—	152,551	7,627,551
Net units issued under SMLP LTIP	161,131	—	1,498	162,629
Units, December 31, 2015	42,062,644	24,409,850	1,354,700	67,827,194

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 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, a subsidiary of Summit Investments completed an underwritten public offering of 4,347,826 SMLP common units 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 2% general partner interest.

Subordination. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution ("MQD," as defined below) plus any arrearages in the payment of the MQD from prior quarters. The subordination period ends on the first business day after we have earned and paid at least $1.60 (the MQD on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015. 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.

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. During the years ended December 31, 2015, 2014 and 2013, net income was attributed to Summit Investments for:

• the 2016 Drop Down Assets for the period from February 16, 2013 to March 3, 2016;

• Polar and Divide for the period from February 16, 2013 to May 18, 2015;

• Red Rock Gathering for the period from January 1, 2013 to March 18, 2014; and

• Bison Midstream for the period from February 16, 2013 to June 4, 2013.

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

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 (dollars in thousands).

Summit Investments' net investment in Polar Midstream and Epping			$	416,044
Total net cash consideration paid to a subsidiary of Summit Investments			285,677
Excess of acquired carrying value over consideration paid			$	130,367
Allocation of capital contribution:
General partner interest	$	2,607
Common limited partner interest	80,079
Subordinated limited partner interest	47,681
Partners' capital contribution – excess of acquired carrying value over consideration paid			$	130,367

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 (dollars in thousands).

Summit Investments' net investment in Red Rock Gathering				$	241,817
Total net cash consideration paid to a subsidiary of Summit Investments				307,941
Excess of consideration paid over acquired carrying value				$	(66,124	)
Allocation of capital distribution:
General partner interest	$	(1,323	)
Common limited partner interest	(37,910		)
Subordinated limited partner interest	(26,891		)
Partners' capital distribution – excess of consideration paid over acquired carrying value				$	(66,124	)

Bison Drop Down. On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. In exchange for its $305.4 million net investment in Bison Midstream, SMLP paid Summit Investments and the general partner total cash and unit consideration of $248.9 million. As a result of the contribution of net assets in excess of consideration, SMLP recognized a capital contribution from Summit Investments.

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

Summit Investments' net investment in Bison Midstream			$	305,449
Aggregate cash paid to Summit Investments	$	200,000
Issuance of 1,553,849 SMLP common units to Summit Investments	47,936
Issuance of 31,711 SMLP general partner units to the general partner	978
Total consideration paid to a subsidiary of Summit Investments			248,914
Excess of acquired carrying value over consideration paid			$	56,535
Allocation of capital contribution:
General partner interest	$	1,131
Common limited partner interest	28,558
Subordinated limited partner interest	26,846
Partners' capital contribution – excess of acquired carrying value over consideration paid			$	56,535

The number of units issued to Summit Investments and the general partner in connection with the Bison Drop Down was calculated based on an assumed equity issuance of $50.0 million and the five-day volume-weighted-average price as of June 3, 2013 of $31.53 per unit. The units were then valued as of June 4, 2013 (the date of closing) using the June 4, 2013 closing price of SMLP's units of $30.85.

The general partner interest allocation was calculated based on a 2% general partner interest in the contribution of assets in excess of consideration given by SMLP to Summit Investments. Common and subordinated limited partner interests allocations were calculated as their respective percentages of total limited partner capital applied to the balance of the contribution by Summit Investments after giving effect to the general partner allocation.

Mountaineer Acquisition. We completed the acquisition of Mountaineer Midstream on June 21, 2013. The purchase price of $210.0 million was funded with $110.0 million of borrowings under SMLP’s revolving credit facility and the issuance for cash of $100.0 million of SMLP common units and general partner interests to a subsidiary of Summit Investments and the general partner.

The allocation and valuation of units issued to partially fund the Mountaineer Acquisition follow (dollars in thousands).

Issuance of 3,107,698 SMLP common units to Summit Investments	$	98,000
Issuance of 63,422 SMLP general partner units to the general partner	2,000
Issuance of units in connection with the Mountaineer Acquisition	$	100,000

Pursuant to a unit purchase agreement, the number of units issued to Summit Investments and the general partner in connection with the Mountaineer Acquisition was calculated based on an assumed equity issuance of $100.0 million and the five-day volume-weighted-average price as of June 3, 2013 of $31.53 per unit.

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.

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

Minimum Quarterly Distribution.Our partnership agreement generally requires that we make a minimum quarterly distribution to the holders of our common units and subordinated 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:

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

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

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

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

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

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

	Year ended December 31,
	2015		2014		2013
Per-unit annual distributions to unitholders	$	2.270	$	2.040	$	1.725

On January 21, 2016, the board of directors of our general partner declared a distribution of $0.575 per unit for the quarterly period ended December 31, 2015. This distribution, which totaled $41.0 million, was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016. As noted above, the payment of this distribution triggered the end of the subordination period and all of the then-outstanding subordinated units converted to common units on a one-for-one basis on February 16, 2016.

We allocated the February 2016 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, up to a maximum of 50.0% (as set forth in the chart below), of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution does not include any distributions that our general partner may receive on any common or subordinated units that it owns.

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 minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units.

	Total quarterly distribution per unit target amount	Marginal percentage interest in distributions
		Unitholders	General partner
Minimum quarterly distribution	$0.40	98.0%	2.0%
First target distribution	$0.40 up to $0.46	98.0%	2.0%
Second target distribution	above $0.46 up to $0.50	85.0%	15.0%
Third target distribution	above $0.50 up to $0.60	75.0%	25.0%
Thereafter	above $0.60	50.0%	50.0%

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 statement of partners' capital during the years ended December 31 follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
IDR payments	$	6,743	$	2,326	$	—

Our general partner was not entitled to receive IDR payments prior to the distribution declared and paid in respect of the fourth quarter of 2013 based on the amount of the distributions declared and paid per common and subordinated unit.

For the purposes of calculating net income attributable to general partner, 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.

XML

EARNINGS PER UNIT

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

EARNINGS PER UNIT

EARNINGS PER UNIT

The following table details the components of EPU.

	Year ended December 31,
	2015			2014			2013
	(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net (loss) income among limited partner interests:
Net (loss) income attributable to common units	$	(125,437	)	$	(16,324	)	$	23,227
Net (loss) income attributable to subordinated units	(70,173		)	(10,793		)	19,322
Net (loss) income attributable to limited partners	$	(195,610	)	$	(27,117	)	$	42,549
Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	39,217			33,311			26,951
Effect of nonvested phantom units	—			—			150
Weighted-average common units outstanding – diluted	39,217			33,311			27,101
Weighted-average subordinated units outstanding – basic and diluted	24,410			24,410			24,410
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.20	)	$	(0.49	)	$	0.86
Common unit – diluted	$	(3.20	)	$	(0.49	)	$	0.86
Subordinated unit – basic and diluted	$	(2.88	)	$	(0.44	)	$	0.79

During the years ended December 31, 2015 and 2014, we excluded 109,201 and 231,875 units, respectively, in our calculation of the effect of nonvested phantom units because they were anti-dilutive. There were no anti-dilutive units during for the year ended December 31, 2013.

XML

UNIT-BASED AND NONCASH COMPENSATION

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

UNIT-BASED COMPENSATION

UNIT-BASED AND NONCASH COMPENSATION

SMLP Long-Term Incentive Plan. The 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, 2015, approximately 4.4 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.

The following table presents phantom and restricted unit activity:

	Units		Weighted-average grant date fair value
Nonvested phantom and restricted units, January 1, 2013	131,558		$	20.00
Phantom and restricted units granted	156,165		26.33
Phantom units forfeited	(4,041	)	25.99
Nonvested phantom and restricted units, December 31, 2013	283,682		23.41
Phantom units granted	136,867		42.32
Phantom and restricted units vested	(61,917	)	25.33
Phantom units forfeited	(22,430	)	25.56
Nonvested phantom units, December 31, 2014	336,202		30.61
Phantom units granted	289,735		29.21
Phantom units vested	(229,497	)	27.66
Phantom units forfeited	(16,529	)	35.09
Nonvested phantom units, December 31, 2015	379,911		$	31.13

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.

As of December 31, 2015, the unrecognized unit-based compensation related to the SMLP LTIP was $5.5 million. Incremental unit-based compensation will be recorded over the remaining vesting period of approximately 1.17 years. Due to the limited and immaterial forfeiture history associated with the grants under the SMLP LTIP, no forfeitures were assumed in the determination of estimated compensation expense.

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

	Year ended December 31,
	2015		2014		2013
	(In thousands)
SMLP LTIP unit-based compensation	$	6,174	$	4,696	$	2,999

SMP Net Profits Interests. In connection with the formation of Summit Investments in 2009, up to 7.5% of total membership interests were authorized for issuance. SMP Net Profits Interests were granted through January 2012. Each grant vests ratably over five years and provides for accelerated vesting in certain limited circumstances. Summit Investments valued the SMP Net Profits Interests utilizing an option pricing method, which modeled membership interests as call options on the underlying equity value of Summit Investments and considered the rights and preferences of each class of equity to allocate a fair value to each class. Summit Investments retained the SMP Net Profits Interests and, as such, they are not reflected in SMLP's financial statements subsequent to the IPO, except as noted below.

Due to common control, we recognized the SMP Net Profits Interests' noncash compensation expense that had been allocated to the contributed subsidiaries prior to their respective drop down date. Noncash compensation recognized in general and administrative expense related to the SMP Net Profits Interests was $0.8 million in 2015, $1.1 million in 2014 and $1.2 million in 2013.

DFW Net Profits Interests. In connection with the formation of DFW Midstream in 2009, up to 5% of DFW Midstream's total membership interests were authorized for issuance (the "DFW Net Profits Interests"). Grants were made in 2009 and 2010. Each grant vested ratably over four years and provided for accelerated vesting in certain limited circumstances. The DFW Net Profits Interests were valued utilizing an option pricing method, which modeled membership interests as call options on the underlying equity value of DFW Midstream and considered the rights and preferences of each class of equity to allocate a fair value to each class.

Beginning in October 2012 and continuing into April 2013, we entered into a series of repurchases with the remaining seven holders of the then-outstanding DFW Net Profits Interests whereby we exchanged $12.2 million for their vested DFW Net Profits Interests and 7,393 SMLP restricted units for their unvested DFW Net Profits Interests. The repurchase prices were determined by valuing the vested and unvested net profits interests in relation to the enterprise value of DFW Midstream and represented fair value at the dates of repurchase. Upon the conclusion of these repurchase transactions, there were no remaining or outstanding DFW Net Profits Interests.

XML

RELATED-PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

RELATED-PARTY TRANSACTIONS

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, the Bison 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:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Operation and maintenance expense	$	25,050	$	22,004	$	15,095
General and administrative expense	26,193		24,993		21,084

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

• certain support expenses and capital expenditures on behalf of the contributed subsidiaries. These transactions were settled periodically through membership interests prior to the respective drop down;

• interest expense that was related to capital projects for the contributed subsidiaries. As such, the associated interest expense was allocated to the respective contributed subsidiary's capital projects as a noncash contribution and capitalized into the basis of the asset; and

• SMP Net Profits Interests accounted for as compensatory awards. As such, the annual expense associated with the SMP Net Profits was allocated to the respective contributed subsidiary and is reflected in general and administrative expenses in the statement of operations.

XML

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Rent expense	$	2,395	$	1,881	$	1,616

Future minimum lease payments for the Partnership's operating leases are immaterial.

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 gathering 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 currently available information, it is at least reasonably possible that the rupture occurred on or prior to December 31, 2014. As such, Summit Investments 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 is covered by Summit Investments' insurance policies, is 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. Property and business interruption claim requests have been submitted, although no amounts have been recognized for any potential recoveries, under the property and business interruption insurance policy.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2014	$	—
Initial accrual	30,000
Accrued environmental remediation, December 31, 2014	30,000
Payments made by affiliates	(13,136		)
Payments made with proceeds from insurance policies	(25,000		)
Additional accruals	21,800
Accrued environmental remediation, December 31, 2015	$	13,664

As of December 31, 2015, 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, 2016. 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, 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.

On June 19, 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.

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Acquisitions and Drop Down Transactions

ACQUISITIONS AND DROP DOWN TRANSACTIONS

2016 Drop Down. On March 3, 2016, the Partnership acquired 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 consideration for the 2016 Drop Down Assets (i) consisted of a cash payment to SMP Holdings of $360.0 million (the “Initial Payment”), funded with borrowings under our revolving credit facility and (ii) includes a deferred payment in 2020 (the “Deferred Purchase Price Obligation”).  The Deferred Purchase Price Obligation will be equal to:

• six-and-one-half (6.5) multiplied by the average Business Adjusted EBITDA, as defined below and in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster, as defined in the Contribution Agreement;

• less the Initial Payment;

• less all capital expenditures incurred for the 2016 Drop Down Assets between the Initial Close and December 31, 2019;

• plus all Business Adjusted EBITDA from the 2016 Drop Down Assets between Initial Close and December 31, 2019, less the Cumulative G&A Adjuster, as defined in the Contribution Agreement. 

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

• plus interest expense, income tax expense, and depreciation and amortization of the 2016 Drop Down Assets for such period;

• plus any adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses with respect to the 2016 Drop Down Assets for such period;

• plus any Special Liability Expenses, as defined below and in the Contribution Agreement, for such period;

• less interest income and income tax benefit of the 2016 Drop Down Assets for such period;

• less adjustments related to any other noncash income or gains with respect to 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, and 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 Initial Close, the Deferred Purchase Price Obligation was estimated to be $860.3 million (based on management’s estimate of the Partnership’s share of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets) and had a net present value of $507.4 million, using a discount rate of 13%.

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. As of December 31, 2014, we assigned the full purchase price to property, plant and equipment.

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

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 assets acquired 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 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):

Purchase price assigned to Meadowlark Midstream			$	25,376
Current assets	$	2,227
Property, plant, and equipment	18,795
Other noncurrent assets	4,354
Total assets acquired	25,376
Total liabilities assumed	$	—
Net identifiable assets acquired			$	25,376

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 gathering 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) $92.5 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.

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

Purchase price assigned to Polar Midstream			$	216,105
Current assets	$	368
Property, plant, and equipment	9,755
Other noncurrent assets	7,201
Total assets acquired	17,324
Current liabilities	4,592
Total liabilities assumed	$	4,592
Net identifiable assets acquired			12,732
Goodwill			$	203,373

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 ("Lonestar") 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 is accounting 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.

Bison Gas Gathering System.On February 15, 2013, Summit Investments acquired BTE. On June 4, 2013, a subsidiary of Summit Investments entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. The Bison Gas Gathering system was carved out from Meadowlark Midstream and primarily gathers associated natural gas production from customers operating in Mountrail and Burke counties in North Dakota under long-term contracts ranging from five years to 15 years. The weighted-average life of the acquired contracts was12 years upon acquisition.

Summit Investments accounted for its purchase of BTE (the "BTE Transaction") 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 February 15, 2013. The intangible assets that were acquired are composed of gas gathering agreement contract values and rights-of-way easements. 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.

Because the Bison Drop Down was executed between entities under common control, SMLP recognized the acquisition of the Bison Gas Gathering system at historical cost which reflected Summit Investments fair value accounting for the BTE Transaction. Furthermore, due to the common control aspect, the Bison Drop Down was accounted for by SMLP on an “as-if pooled” basis for all periods in which common control existed. Common control began on February 15, 2013 concurrent with the BTE Transaction.

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

Purchase price assigned to Bison Gas Gathering system			$	303,168
Current assets	$	5,705
Property, plant, and equipment	85,477
Intangible assets	164,502
Other noncurrent assets	2,187
Total assets acquired	257,871
Current liabilities	6,112
Other noncurrent liabilities	2,790
Total liabilities assumed	$	8,902
Net identifiable assets acquired			248,969
Goodwill			$	54,199

The Bison Drop Down closed on June 4, 2013. The total acquisition purchase price of $248.9 million was funded with $200.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $47.9 million of SMLP common units to Summit Investments and $1.0 million of general partner interests to SMLP’s general partner. Summit Investments had a net investment in the Bison Gas Gathering system of $303.2 million and received total consideration of $248.9 million from SMLP. As a result, SMLP recognized a capital contribution from Summit Investments for the contribution of net assets in excess of consideration paid.

Mountaineer Midstream. We completed the Mountaineer Acquisition on June 21, 2013 for $210.0 million cash consideration. The Mountaineer Midstream natural gas gathering and compression assets are located in the Appalachian Basin which includes the Marcellus Shale formation primarily in Doddridge and Harrison counties in northern West Virginia. The Mountaineer Midstream system consists of newly constructed, high-pressure gas gathering pipelines, certain rights-of-way associated with the pipeline, and two compressor stations. The assets gather natural gas under a long-term, fee-based contract with Antero Resources Corp. ("Antero"). The life of the acquired contract was 13 years upon acquisition.

The Mountaineer Acquisition was funded with $110.0 million of borrowings under the Partnership's revolving credit agreement and the issuance of $100.0 million of common and general partner interests to a subsidiary of Summit Investments. For the year ended December 31, 2013, SMLP recorded $9.6 million of revenue and $2.3 million of net income related to Mountaineer Midstream.

SMLP accounted for the Mountaineer Acquisition under the acquisition method of accounting. As of June 30, 2013, we preliminarily assigned the full $210.0 million purchase price to property plant and equipment. During the third quarter of 2013, we received additional information and, as a result, preliminarily assigned $158.3 million of the purchase price to property, plant and equipment, $27.1 million to contract intangibles, $6.5 million to rights-of-way and $18.1 million to goodwill. During the fourth quarter of 2013, we received additional information from the seller and finalized the purchase price allocation.

The final fair values of the assets acquired and liabilities assumed as of June 21, 2013, were as follows (in thousands):

Purchase price assigned to Mountaineer Midstream			$	210,000
Property, plant, and equipment	$	163,661
Gas gathering agreement contract intangibles	24,019
Rights-of-way	6,109
Total assets acquired	193,789
Total liabilities assumed	$	—
Net identifiable assets acquired			193,789
Goodwill			$	16,211

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 2016 Drop Down, Polar Midstream, Red Rock Gathering and the Bison Gas Gathering system have been combined to reflect the historical operations, financial position and cash flows 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.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
SMLP revenues	$	358,046		$	338,941		$	241,089
2016 Drop Down Assets revenues (1)	29,238			14,466			2,474
Polar and Divide revenues (1)	13,273			22,449			3,893
Red Rock Gathering revenues (1)				11,313			50,114
Bison Gas Gathering system revenues (1)							28,590
Combined revenues	$	400,557		$	387,169		$	326,160
SMLP net (loss) income	$	(192,212	)	$	(23,992	)	$	43,584
2016 Drop Down Assets net loss (1)	(35,419		)	(32,634		)	(5,829		)
Polar and Divide net income (loss) (1)	5,403			6,430			(467		)
Red Rock Gathering net income (1)				2,828			9,668
Bison Gas Gathering system net income (1)							52
Combined net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008

__________

(1) Results are fully reflected in SMLP's revenues and net income on the date common control began, see Note 1.

Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that:

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

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

• Pro forma adjustments also reflect the impact of 4,661,547 common unit issuance and the general partner capital contribution to maintain its 2% general partner interest to fund the acquisition of Bison Midstream and Mountaineer Midstream.

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

• Pro forma adjustments (other than an adjustment for interest expense as discussed below) for the 2016 Drop Down Assets are not required because the assets were not in service prior to common control beginning in February 2013. Interest expense was assumed based on the impact of $360.0 million of incremental borrowings on our revolving credit facility, partially offset by the pro forma derecognition of interest expense allocated to the 2016 Drop Down Assets from Summit Investments (see Note 9).

• Pro forma adjustments for Polar and Divide are not required because the system was not in service prior to common control beginning in February 2013.

• The acquisition of the Lonestar assets is immaterial for pro forma purposes and as such has not been reflected below.

	Year ended December 31, 2013
	(In thousands, except for per-unit amounts)
Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues	$	87,196
Total Bison Midstream and Mountaineer Midstream net loss included in consolidated net income	(457		)
Pro forma total revenues	$	338,311
Pro forma net income	34,369
Pro forma common EPU - basic and diluted	$	0.68
Pro forma subordinated EPU - basic and diluted	0.62

The unaudited pro forma financial information presented above is not necessarily indicative of (i) what our financial position or results of operations would have been if the acquisitions of Bison Midstream and Mountaineer Midstream had occurred on January 1, 2012, or (ii) what SMLP’s financial position or results of operations will be for any future periods.

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Notes)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

In July 2014 and June 2013, the Co-Issuers issued the Senior Notes. As of December 31, 2015, the Senior Notes were fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the then-Guarantor Subsidiaries and SMLP. Due to the common control nature of the 2016 Drop Down, we are including the following supplemental condensed consolidating financial information. This 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 as-if the guarantor structure that exists subsequent to the August 2016 consent and waiver agreement was executed prior to 2016 (see Note 9).

For purposes of the following consolidating information, each of SMLP and Summit Holdings account for their subsidiary investments under the equity method of accounting.

Condensed Consolidating Balance Sheets. Balance sheets as of December 31, 2015 and 2014 follow.

	December 31, 2015
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	73	$	12,407	$	6,930	$	2,383	$	—		$	21,793
Accounts receivable	—		—		84,021		5,560		—			89,581
Due from affiliate	3,168		151,443		207,651		—		(362,262		)	—
Other current assets	540		—		2,672		361		—			3,573
Total current assets	3,781		163,850		301,274		8,304		(362,262		)	114,947
Property, plant and equipment, net	1,178		—		1,462,623		348,982		—			1,812,783
Intangible assets, net	—		—		438,093		23,217		—			461,310
Goodwill	—		—		16,211		—		—			16,211
Investment in equity method investees	—		—		—		751,168		—			751,168
Other noncurrent assets	3,480		4,611		162		—		—			8,253
Investment in subsidiaries	2,438,395		3,222,187		—		—		(5,660,582		)	—
Total assets	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672
Liabilities and Partners' Capital
Trade accounts payable	$	482	$	—	$	18,489	$	21,837	$	—		$	40,808
Due to affiliate	360,243		—		—		3,168		(362,262		)	1,149
Deferred revenue	—		—		677		—		—			677
Ad valorem taxes payable	9		—		9,881		381		—			10,271
Accrued interest	—		17,483		—		—		—			17,483
Accrued environmental remediation	—		—		—		7,900		—			7,900
Other current liabilities	4,558		—		7,405		1,334		—			13,297
Total current liabilities	365,292		17,483		36,452		34,620		(362,262		)	91,585
Long-term debt	332,500		934,770		—		—		—			1,267,270
Deferred revenue	—		—		45,486		—		—			45,486
Noncurrent accrued environmental remediation	—		—		—		5,764		—			5,764
Other noncurrent liabilities	1,743		—		5,503		22		—			7,268
Total liabilities	699,535		952,253		87,441		40,406		(362,262		)	1,417,373
Total partners' capital	1,747,299		2,438,395		2,130,922		1,091,265		(5,660,582		)	1,747,299
Total liabilities and partners' capital	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672

	December 31, 2014
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	7,531	$	11,621	$	7,353	$	1,306	$	—		$	27,811
Accounts receivable	—		—		89,201		3,707		—			92,908
Insurance receivable	—		—		—		25,000		—			25,000
Due from affiliate	764		63,239		97,615		—		(161,618		)	—
Other current assets	907		—		2,610		83		—			3,600
Total current assets	9,202		74,860		196,779		30,096		(161,618		)	149,319
Property, plant and equipment, net	1,351		—		1,412,998		208,291		—			1,622,640
Intangible assets, net	—		—		477,734		11,548		—			489,282
Goodwill	—		—		265,062		—		—			265,062
Investment in equity method investees	—		—		—		706,172		—			706,172
Other noncurrent assets	3,771		6,027		189		—		—			9,987
Investment in subsidiaries	2,419,433		3,154,626		—		—		(5,574,059		)	—
Total assets	$	2,433,757	$	3,235,513	$	2,352,762	$	956,107	$	(5,735,677	)	$	3,242,462
Liabilities and Partners' Capital
Trade accounts payable	$	1,144	$	—	$	23,711	$	13,536	$	—		$	38,391
Due to affiliate	163,565		—		—		764		(161,618		)	2,711
Deferred revenue	—		—		2,377		—		—			2,377
Ad valorem taxes payable	23		—		9,095		61		—			9,179
Accrued interest	—		18,858		—		—		—			18,858
Accrued environmental remediation	—		—		—		25,000		—			25,000
Other current liabilities	1,622		15		12,552		1,118		—			15,307
Total current liabilities	166,354		18,873		47,735		40,479		(161,618		)	111,823
Long-term debt	435,000		797,207		—		—		—			1,232,207
Deferred revenue	—		—		55,239		—		—			55,239
Noncurrent accrued environmental remediation	—		—		—		5,000		—			5,000
Other noncurrent liabilities	1,725		—		5,790		—		—			7,515
Total liabilities	603,079		816,080		108,764		45,479		(161,618		)	1,411,784
Total partners' capital	1,830,678		2,419,433		2,243,998		910,628		(5,574,059		)	1,830,678
Total liabilities and partners' capital	$	2,433,757	$	3,235,513	$	2,352,762	$	956,107	$	(5,735,677	)	$	3,242,462

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, 2015, 2014 and 2013 follow.

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	310,830		$	26,989		$	—	$	337,819
Natural gas, NGLs and condensate sales	—			—			42,079			—			—		42,079
Other revenues	—			—			18,411			2,248			—		20,659
Total revenues	—			—			371,320			29,237			—		400,557
Costs and expenses:
Cost of natural gas and NGLs	—			—			31,398			—			—		31,398
Operation and maintenance	—			—			87,286			7,700			—		94,986
General and administrative	—			—			37,926			7,182			—		45,108
Transaction costs	1,342			—			—			—			—		1,342
Depreciation and amortization	603			—			95,586			8,928			—		105,117
Environmental remediation	—			—			—			21,800			—		21,800
Gain on asset sales, net	—			—			(172		)	—			—		(172		)
Long-lived asset impairment	—			—			9,305			—			—		9,305
Goodwill impairment	—			—			248,851			—			—		248,851
Total costs and expenses	1,945			—			510,180			45,610			—		557,735
Other income	2			—			—			—			—		2
Interest expense	(10,494		)	(48,598		)	—			—			—		(59,092		)
Loss before income taxes	(12,437		)	(48,598		)	(138,860		)	(16,373		)	—		(216,268		)
Income tax benefit	603			—			—			—			—		603
Loss from equity method investees	—			—			—			(6,563		)	—		(6,563		)
Equity in earnings of consolidated subsidiaries	(210,394		)	(161,796		)	—			—			372,190		—
Net loss	$	(222,228	)	$	(210,394	)	$	(138,860	)	$	(22,936	)	$	372,190	$	(222,228	)

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	255,211	$	12,267		$	—	$	267,478
Natural gas, NGLs and condensate sales	—			—			97,094		—			—		97,094
Other revenues	—			—			20,398		2,199			—		22,597
Total revenues	—			—			372,703		14,466			—		387,169
Costs and expenses:
Cost of natural gas and NGLs	—			—			72,415		—			—		72,415
Operation and maintenance	—			—			88,927		5,942			—		94,869
General and administrative	—			—			40,447		2,834			—		43,281
Transaction costs	2,985			—			—		—			—		2,985
Depreciation and amortization	588			—			86,762		3,528			—		90,878
Environmental remediation	—			—			—		5,000			—		5,000
Loss on asset sales, net	—			—			442		—			—		442
Long-lived asset impairment	—			—			5,505		—			—		5,505
Goodwill impairment	—			—			54,199		—			—		54,199
Total costs and expenses	3,573			—			348,697		17,304			—		369,574
Other income	—			—			1,189		—			—		1,189
Interest expense	(8,417		)	(40,169		)	—		—			—		(48,586		)
(Loss) income before income taxes	(11,990		)	(40,169		)	25,195		(2,838		)	—		(29,802		)
Income tax (expense) benefit	(1,680		)	—			826		—			—		(854		)
Loss from equity method investees	—			—			—		(16,712		)	—		(16,712		)
Equity in earnings of consolidated subsidiaries	(33,698		)	6,471			—		—			27,227		—
Net (loss) income	$	(47,368	)	$	(33,698	)	$	26,021	$	(19,550	)	$	27,227	$	(47,368	)

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	213,979		$	2,373		$	—		$	216,352
Natural gas, NGLs and condensate sales	—			—			88,185			—			—			88,185
Other revenues	—			—			21,522			101			—			21,623
Total revenues	—			—			323,686			2,474			—			326,160
Costs and expenses:
Cost of natural gas and NGLs	—			—			68,037			—			—			68,037
Operation and maintenance	—			—			77,122			1,053			—			78,175
General and administrative	—			—			33,970			2,746			—			36,716
Transaction costs	2,841			—			—			—						2,841
Depreciation and amortization	454			—			70,122			656			—			71,232
Loss on asset sales, net	—			—			113			—			—			113
Total costs and expenses	3,295			—			249,364			4,455			—			257,114
Other income	5			—			—			—			—			5
Interest expense	(2,141		)	(19,173		)	—			—			—			(21,314		)
(Loss) income before income taxes	(5,431		)	(19,173		)	74,322			(1,981		)	—			47,737
Income tax expense	—			—			(729		)	—			—			(729		)
Equity in earnings of consolidated subsidiaries	52,439			71,612			—			—			(124,051		)	—
Net income (loss)	$	47,008		$	52,439		$	73,593		$	(1,981	)	$	(124,051	)	$	47,008

Condensed Consolidating Statements of Cash Flows. Statements of cash flows for the years ended December 31, 2015, 2014 and 2013 follow.

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	409		$	(46,716	)	$	202,324		$	35,358		$	—	$	191,375
Cash flows from investing activities:
Capital expenditures	(429		)	—			(118,458		)	(153,338		)	—		(272,225		)
Contributions to equity method investees	—			—			—			(86,200		)	—		(86,200		)
Proceeds from asset sales	—			—			323			—			—		323
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618		)	—			—			—			—		(288,618		)
Advances to affiliates	(2,589		)	(88,221		)	(110,003		)	—			200,813		—
Net cash used in investing activities	(291,636		)	(88,221		)	(228,138		)	(239,538		)	200,813		(646,720		)

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(152,074		)	—			—			—		—			(152,074		)
Borrowings under revolving credit facility	180,000			187,000			—			—		—			367,000
Repayments under revolving credit facility	(100,000		)	(51,000		)	—			—		—			(151,000		)
Repayments under term loan	(182,500		)	—			—			—		—			(182,500		)
Deferred loan costs	(135		)	(277		)	—			—		—			(412		)
Proceeds from issuance of common units, net	221,977			—			—			—		—			221,977
Contribution from general partner	4,737			—			—			—		—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	102,500			—			21,719			196,308		—			320,527
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,655			—			3,864			6,360		—			22,879
Other, net	(1,615		)	—			(192		)	—		—			(1,807		)
Advances from affiliates	198,224			—			—			2,589		(200,813		)	—
Net cash provided by financing activities	283,769			135,723			25,391			205,257		(200,813		)	449,327
Net change in cash and cash equivalents	(7,458		)	786			(423		)	1,077		—			(6,018		)
Cash and cash equivalents, beginning of period	7,531			11,621			7,353			1,306		—			27,811
Cash and cash equivalents, end of period	$	73		$	12,407		$	6,930		$	2,383	$	—		$	21,793

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(3,658	)	$	(30,689	)	$	179,685		$	7,615		$	—	$	152,953
Cash flows from investing activities:
Capital expenditures	(460		)	—			(220,360		)	(122,560		)	—		(343,380		)
Initial contribution to Ohio Gathering	—			—			—			(8,360		)	—		(8,360		)
Acquisition of Ohio Gathering Option	—			—			—			(190,000		)	—		(190,000		)
Option Exercise	—			—			—			(382,385		)	—		(382,385		)
Contributions to equity method investees	—			—			—			(145,131		)	—		(145,131		)
Proceeds from asset sales	—			—			325			—			—		325
Acquisition of gathering systems	—			—			(10,872		)	—			—		(10,872		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(305,000		)	—			—			—			—		(305,000		)
Advances to affiliates	(183		)	(174,495		)	(47,271		)	—			221,949		—
Net cash used in investing activities	(305,643		)	(174,495		)	(278,178		)	(848,436		)	221,949		(1,384,803		)

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(122,224		)	—			—			—			—			(122,224		)
Borrowings under revolving credit facility	57,000			237,295			—			—			—			294,295
Repayments under revolving credit facility	(115,000		)	(315,295		)	—			—			—			(430,295		)
Borrowings under term loan	400,000			—			—			—			—			400,000
Repayments under term loan	(100,000		)	—			—			—			—			(100,000		)
Deferred loan costs	(3,003		)	(5,320		)	—			—			—			(8,323		)
Proceeds from issuance of common units, net	197,806			—			—			—			—			197,806
Contribution from general partner	4,235			—			—			—			—			4,235
Cash advance (to) from Summit Investments (from) to contributed subsidiaries, net	(242,000		)	—			81,421			834,962			—			674,383
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,845			—			10,483			1,556			—			24,884
Issuance of senior notes	—			300,000			—			—			—			300,000
Repurchase of equity-based compensation awards	(228		)	—			—			—			—			(228		)
Other, net	(656		)	—			—			—			—			(656		)
Advances from affiliates	221,766			—			—			183			(221,949		)	—
Net cash provided by financing activities	310,541			216,680			91,904			836,701			(221,949		)	1,233,877
Net change in cash and cash equivalents	1,240			11,496			(6,589		)	(4,120		)	—			2,027
Cash and cash equivalents, beginning of period	6,291			125			13,942			5,426			—			25,784
Cash and cash equivalents, end of period	$	7,531		$	11,621		$	7,353		$	1,306		$	—		$	27,811

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by operating activities	$	(544	)	$	(4,799	)	$	141,260		$	(506	)	$	—	$	135,411
Cash flows from investing activities:
Capital expenditures	(930		)	—			(182,048		)	(66,648		)	—		(249,626		)
Proceeds from asset sales	—			—			585			—			—		585
Acquisition of gathering systems	(210,000		)	—			—			—			—		(210,000		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(200,000		)	—			—			—			—		(200,000		)
Advances to affiliates	(84		)	(371,408		)	(36,672		)	—			408,164		—
Net cash used in investing activities	(411,014		)	(371,408		)	(218,135		)	(66,648		)	408,164		(659,041		)

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(90,196		)	—			—		—		—			(90,196		)
Borrowings under revolving credit facility	96,000			380,950			—		—		—			476,950
Repayments under revolving credit facility	(3,000		)	(294,180		)	—		—		—			(297,180		)
Borrowings under term loan	200,000			—			—		—		—			200,000
Repayments under term loan	(100,000		)	—			—		—		—			(100,000		)
Deferred loan costs	(3,451		)	(10,608		)	—		—		—			(14,059		)
Contribution from general partner	2,229			—			—		—		—			2,229
Cash advance (to) from Summit Investments (from) to contributed subsidiaries, net	(193,000		)	—			72,745		70,168		—			(50,087		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	8,088			—			11,964		2,328		—			22,380
Issuance of senior notes	—			300,000			—		—		—			300,000
Repurchase of equity-based compensation awards	(11,957		)	—			—		—		—			(11,957		)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	100,000			—			—		—		—			100,000
Advances from affiliates	408,080			—			—		84		(408,164		)	—
Net cash provided by financing activities	412,793			376,162			84,709		72,580		(408,164		)	538,080
Net change in cash and cash equivalents	1,235			(45		)	7,834		5,426		—			14,450
Cash and cash equivalents, beginning of period	5,056			170			6,108		—		—			11,334
Cash and cash equivalents, end of period	$	6,291		$	125		$	13,942	$	5,426	$	—		$	25,784

XML

UNAUDITED QUARTERLY FINANCIAL DATA

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Financial Data

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, 2015, follows.

	Quarter ended December 31, 2015			Quarter ended September 30, 2015		Quarter ended June 30, 2015			Quarter ended March 31, 2015
	(In thousands, except per-unit amounts)
Total revenues (1)	$	112,414		$	115,201	$	86,855		$	86,087
Net (loss) income attributable to SMLP (2)(3)	$	(220,468	)	$	23,604	$	2,985		$	1,667
Less net (loss) income attributable to general partner, including IDRs	(2,469		)	2,408		1,891			1,568
Net (loss) income attributable to limited partners	$	(217,999	)	$	21,196	$	1,094		$	99
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.28	)	$	0.32	$	0.05		$	0.00
Common unit – diluted	$	(3.28	)	$	0.32	$	0.05		$	0.00
Subordinated unit – basic and diluted	$	(3.28	)	$	0.32	$	(0.03	)	$	0.00

__________

(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 $7.7 million of long-lived asset impairments.

	Quarter ended December 31, 2014			Quarter ended September 30, 2014		Quarter ended June 30, 2014		Quarter ended March 31, 2014
	(In thousands, except per-unit amounts)
Total revenues (1)	$	114,252		$	94,152	$	93,063	$	85,702
Net (loss) income attributable to SMLP (2)	$	(37,686	)	$	6,113	$	4,036	$	3,545
Less net (loss) income attributable to general partner, including IDRs	689			1,204		801		431
Net (loss) income attributable to limited partners	$	(38,375	)	$	4,909	$	3,235	$	3,114
(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.65	)	$	0.08	$	0.05	$	0.08
Common unit – diluted	$	(0.65	)	$	0.08	$	0.05	$	0.08
Subordinated unit – basic and diluted	$	(0.65	)	$	0.08	$	0.05	$	0.02

__________

(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, 2014, net loss attributable to SMLP includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment.

The amounts for total revenues as originally filed on the respective 2015 and 2014 quarterly reports on Form 10-Q have been retrospectively adjusted for the impact of the 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.

	Quarter ended September 30, 2015		Quarter ended June 30, 2015		Quarter ended March 31, 2015
	(In thousands)
Total revenues as originally reported	$	103,249	$	77,274	$	68,579
2016 Drop Down	8,644		5,911		4,870
Bison revenue reclass	3,308		3,670		4,056
Polar and Divide Drop Down	—		—		8,582
Total revenues	$	115,201	$	86,855	$	86,087

	Quarter ended September 30, 2014		Quarter ended June 30, 2014		Quarter ended March 31, 2014
	(In thousands)
Total revenues as originally reported	$	79,030	$	80,796	$	76,202
2016 Drop Down	4,108		2,414		1,922
Bison revenue reclass	5,260		4,665		4,399
Polar and Divide Drop Down	5,754		5,188		3,179
Total revenues	$	94,152	$	93,063	$	85,702

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Basis of Presentation

Presentation and Consolidation. We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board (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.

Cash and Cash Equivalents

Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

Accounts Receivable

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. 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

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.

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.

	Useful lives (In years)
Gathering and processing systems and related equipment	30
Other	4-15

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

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, 2015 or 2014.

Amortizing Intangibles

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 on a units-of-production basis 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. 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.

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

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. 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 deferred loan costs over the life of the revolving credit facility. We recognize amortization of deferred loan costs in interest expense.

Impairment of Long-Lived Assets

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

Derivative Contracts. We have commodity price exposure related to our sale of the physical natural gas we retain from our DFW Midstream customers and our procurement of electricity to operate DFW Midstream's electric-drive compression assets. Our gas gathering agreements with our 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 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 also sell our retainage gas at prices that are based on the Waha Hub Index, we have effectively fixed the relationship between our compression electricity expense and natural gas 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

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:

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

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

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

Commitments and Contingencies

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.

Revenue Recognition

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 our 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 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:

• Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, and/or processing and (ii) crude oil and/or produced water gathering.

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

Certain of our gathering and processing agreements provide for a monthly, quarterly or annual minimum volume commitment ("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 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

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

Income Taxes

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.

In 2014, we elected to apply changes to the determination of cost of goods sold for the Texas Margin Tax which permits the use of accelerated depreciation allowed for federal income tax purposes.

Earnings Per Unit

Earnings or Loss Per Unit ("EPU"). 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) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (ii) the general partner's 2% interest in net income or loss and (iii) 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

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

Environmental Matters

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 receipt is deemed probable.

Transactions under Common Control

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.

Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with debt incurred by SMP or its affiliates which was replaced with bank borrowings or debt capital at the Partnership, we allocate a portion of that debt, net of deferred loan 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

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. There are currently no recent pronouncements that have been issued that we believe may materially affect our financial statements, except as noted below.

In May 2014, the FASB released a joint revenue recognition standard, ASU No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) the Company satisfies a performance obligation. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted.  In July 2015, the FASB reaffirmed the guidance in its April 2015 proposed ASU that defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We are currently in the process of evaluating the impact of this update.

In April 2015, the FASB issued ASU 2015-03. Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. This presentation will result in debt issuance cost being presented the same way debt discounts have historically been handled. In August 2015, the FASB amended ASU 2015-03 to address the presentation and subsequent measurement of debt issuance costs related to line of credit (“LOC”) arrangements. The amendment added a paragraph that states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing deferred debt issuance costs ratably over the term of a LOC arrangement, regardless of whether there are outstanding borrowings under that LOC arrangement.  This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter.  Early adoption is permitted. The adoption of this update has resulted in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes. Debt issuance costs associated with our revolving credit facility will remain in other noncurrent assets. This ASU had no impact on interest expense, net income or loss, EPU or partners' capital.

In September 2015, the FASB issued ASU No. 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). Under ASU 2015-16, an acquirer would be required to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the acquirer must record in the financial statements for the same period, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Entities must also present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, and interim and annual periods thereafter.  Early adoption is permitted. We are currently in the process of evaluating the impact of this update.

In January 2016, the FASB issued ASU No. 2016-01 Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Among other changes, the amendments in ASU 2016-01 supersede the guidance to classify equity securities with readily determinable fair values into different categories and require equity securities to be measured at fair value with changes in the fair value recognized through net income. They also simplify the impairment assessment of equity investments without readily determinable fair values and require use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes. Under ASU 2016-01, an entity will be required to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments, to separately present financial assets and financial liabilities by measurement category and form of financial asset. ASU 2016-01 also clarifies that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. This new standard is effective for fiscal years, and interim periods within those years, beginning after December 31, 2017. Early adoption is permissible, but limited in application. The adoption of this new update could impact the fair value we disclose for certain financial instruments but is not expected to impact amounts recognized in the consolidated financial statements.

XML

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION (Tables)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Reclassifications

The impact of these reclassifications, which had no impact on net (loss) income, total partners' capital or segment adjusted EBITDA, follows.

	Year ended December 31,
	2014		2013
	(In thousands)
Gathering services and related fees	$	15,616	$	16,805
Other revenues	3,952		10,068
Net impact on total revenues	$	19,568	$	26,873
Cost of natural gas and NGLs	$	19,568	$	26,873
Net impact on cost of natural gas and NGLs and total costs and expenses	$	19,568	$	26,873

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Useful lives of Property, Plant and Equipment

Estimates of useful lives follow.

	Useful lives (In years)
Gathering and processing systems and related equipment	30
Other	4-15

Details on property, plant, and equipment follow.

	December 31,
	2015		2014
	(In thousands)
Gathering and processing systems and related equipment	$	1,883,139	$	1,630,250
Construction in progress	75,132		48,500
Land and line fill	11,055		11,057
Other	32,427		58,375
Total	2,001,753		1,748,182
Less accumulated depreciation	188,970		125,542
Property, plant, and equipment, net	$	1,812,783	$	1,622,640

XML

SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of assets by reportable segment

Assets by reportable segment follow.

	December 31,
	2015		2014		2013
	(In thousands)
Assets:
Utica Shale (1)	$	886,224	$	735,587	$	—
Williston Basin	740,361		861,461		680,014
Piceance/DJ Basins	866,095		941,382		936,794
Barnett Shale	416,586		428,935		431,578
Marcellus Shale	233,116		243,884		214,379
Total reportable segment assets	3,142,382		3,211,249		2,262,765
Corporate	22,290		31,213		19,281
Total assets	$	3,164,672	$	3,242,462	$	2,282,046

__________

(1) Represents the investment in equity method investees for Ohio Gathering (see Note 7) and total assets for Summit Utica.

Schedule of segment reporting information

Segment adjusted EBITDA by reportable segment follows.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	35,873	$	6,176	$	—
Williston Basin	34,008		30,009		17,350
Piceance/DJ Basins	110,222		110,763		79,687
Barnett Shale	59,526		60,528		69,473
Marcellus Shale	23,214		15,940		6,333
Total reportable segment adjusted EBITDA	$	262,843	$	223,416	$	172,843

__________

(1) Includes our proportional share of adjusted EBITDA for Ohio Gathering and is reflected as the proportional adjusted EBITDA for equity method investees in the reconciliation of income or loss before income taxes to segment adjusted EBITDA.

Revenues by reportable segment follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Revenues:
Utica Shale	$	4,700	$	190	$	—
Williston Basin	98,929		109,807		81,501
Piceance/DJ Basins	180,418		161,477		129,747
Barnett Shale	88,042		93,001		105,324
Marcellus Shale	28,468		22,694		9,588
Total reportable segment revenues and total revenues	$	400,557	$	387,169	$	326,160

Adjustments related to MVC shortfall payments by reportable segment follow.

	Year ended December 31,
	2015			2014		2013
	(In thousands)
Adjustments related to MVC shortfall payments:
Williston Basin	$	11,870		$	10,743	$	3,600
Piceance/DJ Basins	(21,590		)	15,194		12,395
Barnett Shale	(2,182		)	628		1,030
Total adjustments related to MVC shortfall payments	$	(11,902	)	$	26,565	$	17,025

Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Depreciation and amortization:
Utica Shale	$	1,417	$	—	$	—
Williston Basin	31,376		24,027		16,669
Piceance/DJ Basins	47,433		42,959		36,185
Barnett Shale	16,392		16,601		14,961
Marcellus Shale	8,682		7,648		3,998
Total reportable segment depreciation and amortization	105,300		91,235		71,813
Corporate	603		587		451
Total depreciation and amortization	$	105,903	$	91,822	$	72,264

Capital expenditures by reportable segment follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Capital expenditures:
Utica Shale	$	94,994	$	24,787	$	—
Williston Basin	147,477		227,283		129,236
Piceance/DJ Basins	21,144		42,417		88,104
Barnett Shale	6,875		14,567		29,534
Marcellus Shale	1,306		33,866		1,822
Total reportable segment capital expenditures	271,796		342,920		248,696
Corporate	429		460		930
Total capital expenditures	$	272,225	$	343,380	$	249,626

Schedule of counterparties accounting for more than 10% of total revenues

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

	Year ended December 31,
	2015		2014		2013
Percentage of total revenues (1):
Counterparty A - Piceance/DJ Basins	16	%	18	%	19	%
Counterparty B - Piceance/DJ Basins	14	%	*		*
Counterparty C - Barnett Shale	*		*		14	%

__________

(1) Includes recognition of revenue that was previously deferred in connection with minimum volume commitments (see Notes 2 and 8).

* Less than 10%

Reconciliation of net income to adjusted EBITDA

A reconciliation of (loss) income before income taxes to total reportable segment adjusted EBITDA follows.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Reconciliation of income (loss) before income taxes to segment adjusted EBITDA:
(Loss) income before income taxes	$	(216,268	)	$	(29,802	)	$	47,737
Add:
Allocated corporate expenses	27,352			15,441			10,153
Interest expense	59,092			48,586			21,314
Depreciation and amortization	105,903			91,822			72,264
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based and noncash compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
Interest income	2			4			5
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Total reportable segment adjusted EBITDA	$	262,843		$	223,416		$	172,843

XML

PROPERTY, PLANT, AND EQUIPMENT, NET (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of property, plant, and equipment, net

Estimates of useful lives follow.

	Useful lives (In years)
Gathering and processing systems and related equipment	30
Other	4-15

Details on property, plant, and equipment follow.

	December 31,
	2015		2014
	(In thousands)
Gathering and processing systems and related equipment	$	1,883,139	$	1,630,250
Construction in progress	75,132		48,500
Land and line fill	11,055		11,057
Other	32,427		58,375
Total	2,001,753		1,748,182
Less accumulated depreciation	188,970		125,542
Property, plant, and equipment, net	$	1,812,783	$	1,622,640

Schedule of long-lived asset impairments

For the assets which had fair values below their carrying value, we recognized the following long-lived asset impairments, by segment.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Long-lived asset impairment:
Williston Basin	$	7,554	$	—	$	—
Barnett Shale	531		5,505		—
Piceance/DJ Basins	1,220		—		—

Schedule of depreciation expense and capitalized interest

Depreciation expense and capitalized interest follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Depreciation expense	$	63,915	$	53,064	$	37,947
Capitalized interest	3,372		4,646		6,690

XML

AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible assets and liabilities subject to amortization

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

	December 31, 2015
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(9,534	)	$	14,661
Contract intangibles	12.5	426,464		(111,052		)	315,412
Rights-of-way	26.3	150,143		(18,906		)	131,237
Total intangible assets		$	600,802	$	(139,492	)	$	461,310
Unfavorable gas gathering contract	10.0	$	10,962	$	(6,077	)	$	4,885

	December 31, 2014
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(8,056	)	$	16,139
Contract intangibles	12.5	426,464		(75,713		)	350,751
Rights-of-way	27.0	135,435		(13,043		)	122,392
Total intangible assets		$	586,094	$	(96,812	)	$	489,282
Unfavorable gas gathering contract	10.0	$	10,962	$	(5,385	)	$	5,577

Recognized amortization expense in other revenues and cost and expenses

We recognized amortization expense in other revenues as follows:

	Year ended December 31,
	2015			2014			2013
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(1,478	)	$	(1,741	)	$	(2,078	)
Amortization expense – unfavorable gas gathering contract	692			797			1,046

We recognized amortization expense in costs and expenses as follows:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Amortization expense – contract intangibles	$	35,339	$	32,554	$	28,654
Amortization expense – rights-of-way	5,863		5,260		4,631

Estimated aggregate annual amortization expected to be recognized

The estimated aggregate annual amortization expected to be recognized as of December 31, 2015 for each of the five succeeding fiscal years follows.

	Intangible assets		Unfavorable gas gathering contract
	(In thousands)
2016	$	43,108	$	924
2017	41,959		1,047
2018	41,413		1,035
2019	41,659		1,045
2020	44,305		834

XML

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Rollforward of goodwill by reportable segment

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

	Piceance/DJ Basins			Williston Basin			Marcellus Shale		Total
	(In thousands)
Goodwill, January 1, 2014	$	45,478		$	257,572		$	16,211	$	319,261
Goodwill impairment	—			(54,199		)	—		(54,199		)
Goodwill, December 31, 2014	45,478			203,373			16,211		265,062
Goodwill impairment	(45,478		)	(203,373		)	—		(248,851		)
Goodwill, December 31, 2015	$	—		$	—		$	16,211	$	16,211

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

	December 31,
	2015		2014		2013
	(In thousands)
Accumulated goodwill impairment:
Piceance/DJ Basins	$	45,478	$	—	$	—
Williston Basin	257,572		54,199		—
Total accumulated goodwill impairment	$	303,050	$	54,199	$	—

XML

EQUITY METHOD INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

A rollforward of the investment in equity method investees follows.

	2015			2014
	(In thousands)
Investment in equity method investees, January 1	$	706,172		$	—
Cash contributions	86,200			145,131
Cash distributions	(34,641		)	(2,992		)
Gain (loss) from equity method investees	6,790			(4,472		)
Amortization of basis difference in equity method investees	(13,353		)	(12,240		)
Acquisition of initial interest in Ohio Gathering	—			190,000
January 2014 initial cash contribution	—			8,360
Option Exercise	—			382,385
Investment in equity method investees, December 31	751,168			706,172
December cash distributions	3,472			—
December cash contributions	—			(20,420		)
Basis difference	(156,888		)	(170,241		)
Investment in equity method investees, net of basis difference, November 30	$	597,752		$	515,511

The following table presents summarized balance sheet information for Ohio Gathering.

	November 30,
	2015		2014
	(In thousands)
Total assets	$	1,510,075	$	1,341,007
Total liabilities	59,313		95,391
Members' equity	1,450,762		1,245,616

The following table presents summarized statements of operations information for Ohio Gathering for the twelve months ended November 30, 2015 and for the period of ownership in 2014.

	Twelve months ended November 30, 2015		Ten months ended November 30, 2014
	(In thousands)
Total revenues	$	130,090	$	45,313
Total operating expenses	112,581		66,374
Net income (loss)	16,803		(21,061		)

XML

DEFERRED REVENUE (Tables)

12 Months Ended

Dec. 31, 2015

Deferred Revenue Disclosure [Abstract]

Rollforward of deferred revenue

A rollforward of current deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2014	$	—	$	—	$	1,555	$	1,555
Additions	—		—		2,610		2,610
Less revenue recognized	—		—		1,788		1,788
Current deferred revenue, December 31, 2014	—		—		2,377		2,377
Additions	—		2,743		677		3,420
Less revenue recognized	—		2,743		2,377		5,120
Current deferred revenue, December 31, 2015	$	—	$	—	$	677	$	677

A rollforward of noncurrent deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2014	$	6,389	$	23,294	$	—	$	29,683
Additions	10,743		14,813		—		25,556
Noncurrent deferred revenue, December 31, 2014	17,132		38,107		—		55,239
Additions	11,897		12,765		—		24,662
Less revenue recognized	27		34,388		—		34,415
Noncurrent deferred revenue, December 31, 2015	$	29,002	$	16,484	$	—	$	45,486

XML

DEBT (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of debt and capital leases

Debt consisted of the following:

	December 31,
	2015			2014
	(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (2.93% at December 31, 2015 and 2.67% at December 31, 2014) due November 2018	$	344,000		$	208,000
Summit Holdings 5.50% Senior unsecured notes due August 2022	300,000			300,000
Less unamortized deferred loan costs (1)	(4,139		)	(4,773		)
Summit Holdings 7.50% Senior unsecured notes due July 2021	300,000			300,000
Less unamortized deferred loan costs (1)	(5,091		)	(6,020		)
SMP Holdings variable rate senior secured revolving credit facility (2.43% at December 31, 2015 and 2.17% at December 31, 2014) due February 2019 (2)	115,000			35,000
SMP Holdings variable rate senior secured term loan (2.43% at December 31, 2015 and 2.17% at December 31, 2014) due May 2017 (2)	217,500			400,000
Total long-term debt	$	1,267,270		$	1,232,207

__________

(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 Initial Close.

Schedule of maturities of long-term debt

The aggregate amount of debt maturing during each of the years after December 31, 2015 are as follows:

	Debt
	(In thousands)
2016	$	—
2017 (1)	217,500
2018	344,000
2019 (1)	115,000
2020	—
Thereafter	600,000
Total long-term debt	$	1,276,500

__________

(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 Initial Close.

XML

FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Summary of the estimated fair value of debt instruments

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

	December 31, 2015				December 31, 2014
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings revolving credit facility	$	344,000	$	344,000	$	208,000	$	208,000
Summit Holdings 5.5% senior notes ($300.0 million principal)	295,861		224,000		295,227		281,750
Summit Holdings 7.5% senior notes ($300.0 million principal)	294,909		257,000		293,980		306,750
SMP Holdings revolving credit facility (1)	115,000		115,000		35,000		35,000
SMP Holdings term loan (1)	217,500		217,500		400,000		400,000

__________

(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 Initial Close.

XML

PARTNERS' CAPITAL (Tables)

12 Months Ended

Dec. 31, 2015

Limited Partners' Capital Account [Line Items]

Schedule of partner units activity

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

	Common	Subordinated	General partner	Total
Units, January 1, 2013	24,412,427	24,409,850	996,320	49,818,597
Units issued to a subsidiary of Summit Investments in connection with the Bison Drop Down	1,553,849	—	31,711	1,585,560
Units issued to a subsidiary of Summit Investments in connection with the Mountaineer Acquisition	3,107,698	—	63,422	3,171,120
Net units issued under SMLP LTIP	5,892	—	—	5,892
Units, January 1, 2014	29,079,866	24,409,850	1,091,453	54,581,169
Units issued in connection with the March Equity 2014 Offering	5,300,000	—	108,337	5,408,337
Net units issued under SMLP LTIP	46,647	—	861	47,508
Units, December 31, 2014	34,426,513	24,409,850	1,200,651	60,037,014
Units issued in connection with the May 2015 Equity Offering	7,475,000	—	152,551	7,627,551
Net units issued under SMLP LTIP	161,131	—	1,498	162,629
Units, December 31, 2015	42,062,644	24,409,850	1,354,700	67,827,194

Schedule of partnership target distributions

	Total quarterly distribution per unit target amount	Marginal percentage interest in distributions
		Unitholders	General partner
Minimum quarterly distribution	$0.40	98.0%	2.0%
First target distribution	$0.40 up to $0.46	98.0%	2.0%
Second target distribution	above $0.46 up to $0.50	85.0%	15.0%
Third target distribution	above $0.50 up to $0.60	75.0%	25.0%
Thereafter	above $0.60	50.0%	50.0%

Details of cash distributions

Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the years ended December 31 follow.

	Year ended December 31,
	2015		2014		2013
	(In thousands)
IDR payments	$	6,743	$	2,326	$	—

We paid the following per-unit distributions during the years ended December 31:

	Year ended December 31,
	2015		2014		2013
Per-unit annual distributions to unitholders	$	2.270	$	2.040	$	1.725

Polar Midstream and Epping

Limited Partners' Capital Account [Line Items]

Calculation of capital contribution and its allocation to partners' capital

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

Summit Investments' net investment in Polar Midstream and Epping			$	416,044
Total net cash consideration paid to a subsidiary of Summit Investments			285,677
Excess of acquired carrying value over consideration paid			$	130,367
Allocation of capital contribution:
General partner interest	$	2,607
Common limited partner interest	80,079
Subordinated limited partner interest	47,681
Partners' capital contribution – excess of acquired carrying value over consideration paid			$	130,367

Red Rock Gathering Company, LLC

Limited Partners' Capital Account [Line Items]

Calculation of capital distribution and its allocation to partners' capital

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

Summit Investments' net investment in Red Rock Gathering				$	241,817
Total net cash consideration paid to a subsidiary of Summit Investments				307,941
Excess of consideration paid over acquired carrying value				$	(66,124	)
Allocation of capital distribution:
General partner interest	$	(1,323	)
Common limited partner interest	(37,910		)
Subordinated limited partner interest	(26,891		)
Partners' capital distribution – excess of consideration paid over acquired carrying value				$	(66,124	)

Bison Midstream

Limited Partners' Capital Account [Line Items]

Calculation of capital contribution and its allocation to partners' capital

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

Summit Investments' net investment in Bison Midstream			$	305,449
Aggregate cash paid to Summit Investments	$	200,000
Issuance of 1,553,849 SMLP common units to Summit Investments	47,936
Issuance of 31,711 SMLP general partner units to the general partner	978
Total consideration paid to a subsidiary of Summit Investments			248,914
Excess of acquired carrying value over consideration paid			$	56,535
Allocation of capital contribution:
General partner interest	$	1,131
Common limited partner interest	28,558
Subordinated limited partner interest	26,846
Partners' capital contribution – excess of acquired carrying value over consideration paid			$	56,535

Mountaineer Midstream

Limited Partners' Capital Account [Line Items]

Allocation and valuation of units issued to partially fund

The allocation and valuation of units issued to partially fund the Mountaineer Acquisition follow (dollars in thousands).

Issuance of 3,107,698 SMLP common units to Summit Investments	$	98,000
Issuance of 63,422 SMLP general partner units to the general partner	2,000
Issuance of units in connection with the Mountaineer Acquisition	$	100,000

XML

EARNINGS PER UNIT (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Schedule of earnings per limited partner unit

The following table details the components of EPU.

	Year ended December 31,
	2015			2014			2013
	(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net (loss) income among limited partner interests:
Net (loss) income attributable to common units	$	(125,437	)	$	(16,324	)	$	23,227
Net (loss) income attributable to subordinated units	(70,173		)	(10,793		)	19,322
Net (loss) income attributable to limited partners	$	(195,610	)	$	(27,117	)	$	42,549
Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	39,217			33,311			26,951
Effect of nonvested phantom units	—			—			150
Weighted-average common units outstanding – diluted	39,217			33,311			27,101
Weighted-average subordinated units outstanding – basic and diluted	24,410			24,410			24,410
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.20	)	$	(0.49	)	$	0.86
Common unit – diluted	$	(3.20	)	$	(0.49	)	$	0.86
Subordinated unit – basic and diluted	$	(2.88	)	$	(0.44	)	$	0.79

XML

UNIT-BASED AND NONCASH COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of unit-based compensation recognized in general and administrative expense

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

	Year ended December 31,
	2015		2014		2013
	(In thousands)
SMLP LTIP unit-based compensation	$	6,174	$	4,696	$	2,999

Phantom and Restricted Units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of activity

The following table presents phantom and restricted unit activity:

	Units		Weighted-average grant date fair value
Nonvested phantom and restricted units, January 1, 2013	131,558		$	20.00
Phantom and restricted units granted	156,165		26.33
Phantom units forfeited	(4,041	)	25.99
Nonvested phantom and restricted units, December 31, 2013	283,682		23.41
Phantom units granted	136,867		42.32
Phantom and restricted units vested	(61,917	)	25.33
Phantom units forfeited	(22,430	)	25.56
Nonvested phantom units, December 31, 2014	336,202		30.61
Phantom units granted	289,735		29.21
Phantom units vested	(229,497	)	27.66
Phantom units forfeited	(16,529	)	35.09
Nonvested phantom units, December 31, 2015	379,911		$	31.13

XML

RELATED-PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Schedule of related party transactions

Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Operation and maintenance expense	$	25,050	$	22,004	$	15,095
General and administrative expense	26,193		24,993		21,084

XML

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of total rent expense related to operating leases

Rent expense related to operating leases, including rent expense incurred on our behalf and allocated to us, was as follows:

	Year ended December 31,
	2015		2014		2013
	(In thousands)
Rent expense	$	2,395	$	1,881	$	1,616

Schedule of accrued environmental remediation

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2014	$	—
Initial accrual	30,000
Accrued environmental remediation, December 31, 2014	30,000
Payments made by affiliates	(13,136		)
Payments made with proceeds from insurance policies	(25,000		)
Additional accruals	21,800
Accrued environmental remediation, December 31, 2015	$	13,664

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2015

Business Acquisition [Line Items]

Fair Value of Assets Acquired and Liabilities Assumed

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

Purchase price assigned to Meadowlark Midstream			$	25,376
Current assets	$	2,227
Property, plant, and equipment	18,795
Other noncurrent assets	4,354
Total assets acquired	25,376
Total liabilities assumed	$	—
Net identifiable assets acquired			$	25,376

Schedule of Revenue and Net Income Disclosures

Revenues and net income for the previously separate entities and the combined amounts, as presented in these consolidated financial statements follow.

	Year ended December 31,
	2015			2014			2013
	(In thousands)
SMLP revenues	$	358,046		$	338,941		$	241,089
2016 Drop Down Assets revenues (1)	29,238			14,466			2,474
Polar and Divide revenues (1)	13,273			22,449			3,893
Red Rock Gathering revenues (1)				11,313			50,114
Bison Gas Gathering system revenues (1)							28,590
Combined revenues	$	400,557		$	387,169		$	326,160
SMLP net (loss) income	$	(192,212	)	$	(23,992	)	$	43,584
2016 Drop Down Assets net loss (1)	(35,419		)	(32,634		)	(5,829		)
Polar and Divide net income (loss) (1)	5,403			6,430			(467		)
Red Rock Gathering net income (1)				2,828			9,668
Bison Gas Gathering system net income (1)							52
Combined net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008

__________

(1) Results are fully reflected in SMLP's revenues and net income on the date common control began, see Note 1.

Business Acquisitions, Pro Forma Information

	Year ended December 31, 2013
	(In thousands, except for per-unit amounts)
Total Bison Midstream and Mountaineer Midstream revenues included in consolidated revenues	$	87,196
Total Bison Midstream and Mountaineer Midstream net loss included in consolidated net income	(457		)
Pro forma total revenues	$	338,311
Pro forma net income	34,369
Pro forma common EPU - basic and diluted	$	0.68
Pro forma subordinated EPU - basic and diluted	0.62

Polar Midstream

Business Acquisition [Line Items]

Fair Value of Assets Acquired and Liabilities Assumed

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

Purchase price assigned to Polar Midstream			$	216,105
Current assets	$	368
Property, plant, and equipment	9,755
Other noncurrent assets	7,201
Total assets acquired	17,324
Current liabilities	4,592
Total liabilities assumed	$	4,592
Net identifiable assets acquired			12,732
Goodwill			$	203,373

Bison Midstream

Business Acquisition [Line Items]

Fair Value of Assets Acquired and Liabilities Assumed

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

Purchase price assigned to Bison Gas Gathering system			$	303,168
Current assets	$	5,705
Property, plant, and equipment	85,477
Intangible assets	164,502
Other noncurrent assets	2,187
Total assets acquired	257,871
Current liabilities	6,112
Other noncurrent liabilities	2,790
Total liabilities assumed	$	8,902
Net identifiable assets acquired			248,969
Goodwill			$	54,199

Mountaineer Midstream

Business Acquisition [Line Items]

Fair Value of Assets Acquired and Liabilities Assumed

The final fair values of the assets acquired and liabilities assumed as of June 21, 2013, were as follows (in thousands):

Purchase price assigned to Mountaineer Midstream			$	210,000
Property, plant, and equipment	$	163,661
Gas gathering agreement contract intangibles	24,019
Rights-of-way	6,109
Total assets acquired	193,789
Total liabilities assumed	$	—
Net identifiable assets acquired			193,789
Goodwill			$	16,211

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Balance Sheet

Balance sheets as of December 31, 2015 and 2014 follow.

	December 31, 2015
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	73	$	12,407	$	6,930	$	2,383	$	—		$	21,793
Accounts receivable	—		—		84,021		5,560		—			89,581
Due from affiliate	3,168		151,443		207,651		—		(362,262		)	—
Other current assets	540		—		2,672		361		—			3,573
Total current assets	3,781		163,850		301,274		8,304		(362,262		)	114,947
Property, plant and equipment, net	1,178		—		1,462,623		348,982		—			1,812,783
Intangible assets, net	—		—		438,093		23,217		—			461,310
Goodwill	—		—		16,211		—		—			16,211
Investment in equity method investees	—		—		—		751,168		—			751,168
Other noncurrent assets	3,480		4,611		162		—		—			8,253
Investment in subsidiaries	2,438,395		3,222,187		—		—		(5,660,582		)	—
Total assets	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672
Liabilities and Partners' Capital
Trade accounts payable	$	482	$	—	$	18,489	$	21,837	$	—		$	40,808
Due to affiliate	360,243		—		—		3,168		(362,262		)	1,149
Deferred revenue	—		—		677		—		—			677
Ad valorem taxes payable	9		—		9,881		381		—			10,271
Accrued interest	—		17,483		—		—		—			17,483
Accrued environmental remediation	—		—		—		7,900		—			7,900
Other current liabilities	4,558		—		7,405		1,334		—			13,297
Total current liabilities	365,292		17,483		36,452		34,620		(362,262		)	91,585
Long-term debt	332,500		934,770		—		—		—			1,267,270
Deferred revenue	—		—		45,486		—		—			45,486
Noncurrent accrued environmental remediation	—		—		—		5,764		—			5,764
Other noncurrent liabilities	1,743		—		5,503		22		—			7,268
Total liabilities	699,535		952,253		87,441		40,406		(362,262		)	1,417,373
Total partners' capital	1,747,299		2,438,395		2,130,922		1,091,265		(5,660,582		)	1,747,299
Total liabilities and partners' capital	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672

	December 31, 2014
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	7,531	$	11,621	$	7,353	$	1,306	$	—		$	27,811
Accounts receivable	—		—		89,201		3,707		—			92,908
Insurance receivable	—		—		—		25,000		—			25,000
Due from affiliate	764		63,239		97,615		—		(161,618		)	—
Other current assets	907		—		2,610		83		—			3,600
Total current assets	9,202		74,860		196,779		30,096		(161,618		)	149,319
Property, plant and equipment, net	1,351		—		1,412,998		208,291		—			1,622,640
Intangible assets, net	—		—		477,734		11,548		—			489,282
Goodwill	—		—		265,062		—		—			265,062
Investment in equity method investees	—		—		—		706,172		—			706,172
Other noncurrent assets	3,771		6,027		189		—		—			9,987
Investment in subsidiaries	2,419,433		3,154,626		—		—		(5,574,059		)	—
Total assets	$	2,433,757	$	3,235,513	$	2,352,762	$	956,107	$	(5,735,677	)	$	3,242,462
Liabilities and Partners' Capital
Trade accounts payable	$	1,144	$	—	$	23,711	$	13,536	$	—		$	38,391
Due to affiliate	163,565		—		—		764		(161,618		)	2,711
Deferred revenue	—		—		2,377		—		—			2,377
Ad valorem taxes payable	23		—		9,095		61		—			9,179
Accrued interest	—		18,858		—		—		—			18,858
Accrued environmental remediation	—		—		—		25,000		—			25,000
Other current liabilities	1,622		15		12,552		1,118		—			15,307
Total current liabilities	166,354		18,873		47,735		40,479		(161,618		)	111,823
Long-term debt	435,000		797,207		—		—		—			1,232,207
Deferred revenue	—		—		55,239		—		—			55,239
Noncurrent accrued environmental remediation	—		—		—		5,000		—			5,000
Other noncurrent liabilities	1,725		—		5,790		—		—			7,515
Total liabilities	603,079		816,080		108,764		45,479		(161,618		)	1,411,784
Total partners' capital	1,830,678		2,419,433		2,243,998		910,628		(5,574,059		)	1,830,678
Total liabilities and partners' capital	$	2,433,757	$	3,235,513	$	2,352,762	$	956,107	$	(5,735,677	)	$	3,242,462

Condensed Statement of Operations

Statements of operations for the years ended December 31, 2015, 2014 and 2013 follow.

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	310,830		$	26,989		$	—	$	337,819
Natural gas, NGLs and condensate sales	—			—			42,079			—			—		42,079
Other revenues	—			—			18,411			2,248			—		20,659
Total revenues	—			—			371,320			29,237			—		400,557
Costs and expenses:
Cost of natural gas and NGLs	—			—			31,398			—			—		31,398
Operation and maintenance	—			—			87,286			7,700			—		94,986
General and administrative	—			—			37,926			7,182			—		45,108
Transaction costs	1,342			—			—			—			—		1,342
Depreciation and amortization	603			—			95,586			8,928			—		105,117
Environmental remediation	—			—			—			21,800			—		21,800
Gain on asset sales, net	—			—			(172		)	—			—		(172		)
Long-lived asset impairment	—			—			9,305			—			—		9,305
Goodwill impairment	—			—			248,851			—			—		248,851
Total costs and expenses	1,945			—			510,180			45,610			—		557,735
Other income	2			—			—			—			—		2
Interest expense	(10,494		)	(48,598		)	—			—			—		(59,092		)
Loss before income taxes	(12,437		)	(48,598		)	(138,860		)	(16,373		)	—		(216,268		)
Income tax benefit	603			—			—			—			—		603
Loss from equity method investees	—			—			—			(6,563		)	—		(6,563		)
Equity in earnings of consolidated subsidiaries	(210,394		)	(161,796		)	—			—			372,190		—
Net loss	$	(222,228	)	$	(210,394	)	$	(138,860	)	$	(22,936	)	$	372,190	$	(222,228	)

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	255,211	$	12,267		$	—	$	267,478
Natural gas, NGLs and condensate sales	—			—			97,094		—			—		97,094
Other revenues	—			—			20,398		2,199			—		22,597
Total revenues	—			—			372,703		14,466			—		387,169
Costs and expenses:
Cost of natural gas and NGLs	—			—			72,415		—			—		72,415
Operation and maintenance	—			—			88,927		5,942			—		94,869
General and administrative	—			—			40,447		2,834			—		43,281
Transaction costs	2,985			—			—		—			—		2,985
Depreciation and amortization	588			—			86,762		3,528			—		90,878
Environmental remediation	—			—			—		5,000			—		5,000
Loss on asset sales, net	—			—			442		—			—		442
Long-lived asset impairment	—			—			5,505		—			—		5,505
Goodwill impairment	—			—			54,199		—			—		54,199
Total costs and expenses	3,573			—			348,697		17,304			—		369,574
Other income	—			—			1,189		—			—		1,189
Interest expense	(8,417		)	(40,169		)	—		—			—		(48,586		)
(Loss) income before income taxes	(11,990		)	(40,169		)	25,195		(2,838		)	—		(29,802		)
Income tax (expense) benefit	(1,680		)	—			826		—			—		(854		)
Loss from equity method investees	—			—			—		(16,712		)	—		(16,712		)
Equity in earnings of consolidated subsidiaries	(33,698		)	6,471			—		—			27,227		—
Net (loss) income	$	(47,368	)	$	(33,698	)	$	26,021	$	(19,550	)	$	27,227	$	(47,368	)

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	213,979		$	2,373		$	—		$	216,352
Natural gas, NGLs and condensate sales	—			—			88,185			—			—			88,185
Other revenues	—			—			21,522			101			—			21,623
Total revenues	—			—			323,686			2,474			—			326,160
Costs and expenses:
Cost of natural gas and NGLs	—			—			68,037			—			—			68,037
Operation and maintenance	—			—			77,122			1,053			—			78,175
General and administrative	—			—			33,970			2,746			—			36,716
Transaction costs	2,841			—			—			—						2,841
Depreciation and amortization	454			—			70,122			656			—			71,232
Loss on asset sales, net	—			—			113			—			—			113
Total costs and expenses	3,295			—			249,364			4,455			—			257,114
Other income	5			—			—			—			—			5
Interest expense	(2,141		)	(19,173		)	—			—			—			(21,314		)
(Loss) income before income taxes	(5,431		)	(19,173		)	74,322			(1,981		)	—			47,737
Income tax expense	—			—			(729		)	—			—			(729		)
Equity in earnings of consolidated subsidiaries	52,439			71,612			—			—			(124,051		)	—
Net income (loss)	$	47,008		$	52,439		$	73,593		$	(1,981	)	$	(124,051	)	$	47,008

Condensed Cash Flow Statement

Statements of cash flows for the years ended December 31, 2015, 2014 and 2013 follow.

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	409		$	(46,716	)	$	202,324		$	35,358		$	—	$	191,375
Cash flows from investing activities:
Capital expenditures	(429		)	—			(118,458		)	(153,338		)	—		(272,225		)
Contributions to equity method investees	—			—			—			(86,200		)	—		(86,200		)
Proceeds from asset sales	—			—			323			—			—		323
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618		)	—			—			—			—		(288,618		)
Advances to affiliates	(2,589		)	(88,221		)	(110,003		)	—			200,813		—
Net cash used in investing activities	(291,636		)	(88,221		)	(228,138		)	(239,538		)	200,813		(646,720		)

	Year ended December 31, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(152,074		)	—			—			—		—			(152,074		)
Borrowings under revolving credit facility	180,000			187,000			—			—		—			367,000
Repayments under revolving credit facility	(100,000		)	(51,000		)	—			—		—			(151,000		)
Repayments under term loan	(182,500		)	—			—			—		—			(182,500		)
Deferred loan costs	(135		)	(277		)	—			—		—			(412		)
Proceeds from issuance of common units, net	221,977			—			—			—		—			221,977
Contribution from general partner	4,737			—			—			—		—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	102,500			—			21,719			196,308		—			320,527
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,655			—			3,864			6,360		—			22,879
Other, net	(1,615		)	—			(192		)	—		—			(1,807		)
Advances from affiliates	198,224			—			—			2,589		(200,813		)	—
Net cash provided by financing activities	283,769			135,723			25,391			205,257		(200,813		)	449,327
Net change in cash and cash equivalents	(7,458		)	786			(423		)	1,077		—			(6,018		)
Cash and cash equivalents, beginning of period	7,531			11,621			7,353			1,306		—			27,811
Cash and cash equivalents, end of period	$	73		$	12,407		$	6,930		$	2,383	$	—		$	21,793

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash (used in) provided by operating activities	$	(3,658	)	$	(30,689	)	$	179,685		$	7,615		$	—	$	152,953
Cash flows from investing activities:
Capital expenditures	(460		)	—			(220,360		)	(122,560		)	—		(343,380		)
Initial contribution to Ohio Gathering	—			—			—			(8,360		)	—		(8,360		)
Acquisition of Ohio Gathering Option	—			—			—			(190,000		)	—		(190,000		)
Option Exercise	—			—			—			(382,385		)	—		(382,385		)
Contributions to equity method investees	—			—			—			(145,131		)	—		(145,131		)
Proceeds from asset sales	—			—			325			—			—		325
Acquisition of gathering systems	—			—			(10,872		)	—			—		(10,872		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(305,000		)	—			—			—			—		(305,000		)
Advances to affiliates	(183		)	(174,495		)	(47,271		)	—			221,949		—
Net cash used in investing activities	(305,643		)	(174,495		)	(278,178		)	(848,436		)	221,949		(1,384,803		)

	Year ended December 31, 2014
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(122,224		)	—			—			—			—			(122,224		)
Borrowings under revolving credit facility	57,000			237,295			—			—			—			294,295
Repayments under revolving credit facility	(115,000		)	(315,295		)	—			—			—			(430,295		)
Borrowings under term loan	400,000			—			—			—			—			400,000
Repayments under term loan	(100,000		)	—			—			—			—			(100,000		)
Deferred loan costs	(3,003		)	(5,320		)	—			—			—			(8,323		)
Proceeds from issuance of common units, net	197,806			—			—			—			—			197,806
Contribution from general partner	4,235			—			—			—			—			4,235
Cash advance (to) from Summit Investments (from) to contributed subsidiaries, net	(242,000		)	—			81,421			834,962			—			674,383
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,845			—			10,483			1,556			—			24,884
Issuance of senior notes	—			300,000			—			—			—			300,000
Repurchase of equity-based compensation awards	(228		)	—			—			—			—			(228		)
Other, net	(656		)	—			—			—			—			(656		)
Advances from affiliates	221,766			—			—			183			(221,949		)	—
Net cash provided by financing activities	310,541			216,680			91,904			836,701			(221,949		)	1,233,877
Net change in cash and cash equivalents	1,240			11,496			(6,589		)	(4,120		)	—			2,027
Cash and cash equivalents, beginning of period	6,291			125			13,942			5,426			—			25,784
Cash and cash equivalents, end of period	$	7,531		$	11,621		$	7,353		$	1,306		$	—		$	27,811

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments		Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by operating activities	$	(544	)	$	(4,799	)	$	141,260		$	(506	)	$	—	$	135,411
Cash flows from investing activities:
Capital expenditures	(930		)	—			(182,048		)	(66,648		)	—		(249,626		)
Proceeds from asset sales	—			—			585			—			—		585
Acquisition of gathering systems	(210,000		)	—			—			—			—		(210,000		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(200,000		)	—			—			—			—		(200,000		)
Advances to affiliates	(84		)	(371,408		)	(36,672		)	—			408,164		—
Net cash used in investing activities	(411,014		)	(371,408		)	(218,135		)	(66,648		)	408,164		(659,041		)

	Year ended December 31, 2013
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(90,196		)	—			—		—		—			(90,196		)
Borrowings under revolving credit facility	96,000			380,950			—		—		—			476,950
Repayments under revolving credit facility	(3,000		)	(294,180		)	—		—		—			(297,180		)
Borrowings under term loan	200,000			—			—		—		—			200,000
Repayments under term loan	(100,000		)	—			—		—		—			(100,000		)
Deferred loan costs	(3,451		)	(10,608		)	—		—		—			(14,059		)
Contribution from general partner	2,229			—			—		—		—			2,229
Cash advance (to) from Summit Investments (from) to contributed subsidiaries, net	(193,000		)	—			72,745		70,168		—			(50,087		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	8,088			—			11,964		2,328		—			22,380
Issuance of senior notes	—			300,000			—		—		—			300,000
Repurchase of equity-based compensation awards	(11,957		)	—			—		—		—			(11,957		)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	100,000			—			—		—		—			100,000
Advances from affiliates	408,080			—			—		84		(408,164		)	—
Net cash provided by financing activities	412,793			376,162			84,709		72,580		(408,164		)	538,080
Net change in cash and cash equivalents	1,235			(45		)	7,834		5,426		—			14,450
Cash and cash equivalents, beginning of period	5,056			170			6,108		—		—			11,334
Cash and cash equivalents, end of period	$	6,291		$	125		$	13,942	$	5,426	$	—		$	25,784

XML

UNAUDITED QUARTERLY FINANCIAL DATA (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly summarized information on the consolidated results of operations

Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2015, follows.

	Quarter ended December 31, 2015			Quarter ended September 30, 2015		Quarter ended June 30, 2015			Quarter ended March 31, 2015
	(In thousands, except per-unit amounts)
Total revenues (1)	$	112,414		$	115,201	$	86,855		$	86,087
Net (loss) income attributable to SMLP (2)(3)	$	(220,468	)	$	23,604	$	2,985		$	1,667
Less net (loss) income attributable to general partner, including IDRs	(2,469		)	2,408		1,891			1,568
Net (loss) income attributable to limited partners	$	(217,999	)	$	21,196	$	1,094		$	99
(Loss) earnings per limited partner unit:
Common unit – basic	$	(3.28	)	$	0.32	$	0.05		$	0.00
Common unit – diluted	$	(3.28	)	$	0.32	$	0.05		$	0.00
Subordinated unit – basic and diluted	$	(3.28	)	$	0.32	$	(0.03	)	$	0.00

__________

(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 $7.7 million of long-lived asset impairments.

	Quarter ended December 31, 2014			Quarter ended September 30, 2014		Quarter ended June 30, 2014		Quarter ended March 31, 2014
	(In thousands, except per-unit amounts)
Total revenues (1)	$	114,252		$	94,152	$	93,063	$	85,702
Net (loss) income attributable to SMLP (2)	$	(37,686	)	$	6,113	$	4,036	$	3,545
Less net (loss) income attributable to general partner, including IDRs	689			1,204		801		431
Net (loss) income attributable to limited partners	$	(38,375	)	$	4,909	$	3,235	$	3,114
(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.65	)	$	0.08	$	0.05	$	0.08
Common unit – diluted	$	(0.65	)	$	0.08	$	0.05	$	0.08
Subordinated unit – basic and diluted	$	(0.65	)	$	0.08	$	0.05	$	0.02

__________

(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, 2014, net loss attributable to SMLP includes $54.2 million of goodwill impairment and $5.5 million of long-lived asset impairment.

Retrospective adjustments from impact of acquisitions

A reconciliation of total revenues follows.

	Quarter ended September 30, 2015		Quarter ended June 30, 2015		Quarter ended March 31, 2015
	(In thousands)
Total revenues as originally reported	$	103,249	$	77,274	$	68,579
2016 Drop Down	8,644		5,911		4,870
Bison revenue reclass	3,308		3,670		4,056
Polar and Divide Drop Down	—		—		8,582
Total revenues	$	115,201	$	86,855	$	86,087

	Quarter ended September 30, 2014		Quarter ended June 30, 2014		Quarter ended March 31, 2014
	(In thousands)
Total revenues as originally reported	$	79,030	$	80,796	$	76,202
2016 Drop Down	4,108		2,414		1,922
Bison revenue reclass	5,260		4,665		4,399
Polar and Divide Drop Down	5,754		5,188		3,179
Total revenues	$	94,152	$	93,063	$	85,702

XML

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION (Details) $ in Millions		1 Months Ended				3 Months Ended	12 Months Ended
	Feb. 25, 2016	May 31, 2015	Mar. 31, 2014	Mar. 31, 2013	Oct. 31, 2012	Dec. 31, 2015 USD ($) segment shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013	Mar. 03, 2016
ORGANIZATION AND BUSINESS OPERATIONS
Common limited partner capital, units outstanding | shares						42,063,000	42,063,000	34,427,000
Williston Basin Segment
ORGANIZATION AND BUSINESS OPERATIONS
Number of reportable segments | segment						1
Summit Holdings
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership in subsidiary					100.00%
SMP Holdings | Ohio Gathering | Subsequent Event
ORGANIZATION AND BUSINESS OPERATIONS
Join venture interest	40.00%
Summit Holdings | DFW Midstream
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership in subsidiary					100.00%
Summit Holdings | Grand River
ORGANIZATION AND BUSINESS OPERATIONS
Cumulative percentage ownership in subsidiary					100.00%
Drop Down Assets 2016 Acquisition | Subsequent Event
ORGANIZATION AND BUSINESS OPERATIONS
Ownership percentage by noncontrolling owners										1.00%
Common units | SMP Holdings
ORGANIZATION AND BUSINESS OPERATIONS
Common limited partner capital, units outstanding | shares						5,444,731	5,444,731
General partner
ORGANIZATION AND BUSINESS OPERATIONS
General partner interest (as a percent)		2.00%	2.00%				2.00%	2.00%	2.00%
General partner | Summit Investments | Summit Midstream Partners, LP
ORGANIZATION AND BUSINESS OPERATIONS
General partner interest (as a percent)				2.00%
Accounting Standards Update 2015-03 | Other noncurrent assets
ORGANIZATION AND BUSINESS OPERATIONS
Deferred Finance Costs, Net | $						$ 9.2	$ 9.2	$ 10.8
Accounting Standards Update 2015-03 | Long-term debt
ORGANIZATION AND BUSINESS OPERATIONS
Deferred Finance Costs, Net | $						$ (9.2)	$ (9.2)	$ (10.8)

XML

ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION - Reclassifications (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Gathering services and related fees									$ 337,819	$ 267,478	$ 216,352
Other revenues									20,659	22,597	21,623
Net impact on total revenues	$ 112,414	$ 115,201	$ 86,855	$ 86,087	$ 114,252	$ 94,152	$ 93,063	$ 85,702	400,557	387,169	326,160
Cost of natural gas and NGLs									31,398	72,415	68,037
Net impact on cost of natural gas and NGLs and total costs and expenses									$ 557,735	369,574	257,114
Reclassifications of Revenues and Expenses
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Gathering services and related fees										15,616	16,805
Other revenues										3,952	10,068
Net impact on total revenues										19,568	26,873
Cost of natural gas and NGLs										19,568	26,873
Net impact on cost of natural gas and NGLs and total costs and expenses										$ 19,568	$ 26,873

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2015
Gathering and processing systems and related equipment
Property, Plant and Equipment [Line Items]
Useful life	30 years
Other | Minimum
Property, Plant and Equipment [Line Items]
Useful life	4 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Useful life	15 years

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Intangible Assets and Noncurrent Liability (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Favorable gas gathering contract
Finite-Lived Intangible Assets [Line Items]
Useful lives	18 years 8 months 12 days	18 years 8 months 12 days
Favorable gas gathering contract | Minimum
Finite-Lived Intangible Assets [Line Items]
Useful lives	10 years
Favorable gas gathering contract | Maximum
Finite-Lived Intangible Assets [Line Items]
Useful lives	20 years
Other Gas Gathering Contract | Maximum
Finite-Lived Intangible Assets [Line Items]
Useful lives	25 years
Rights-of-way
Finite-Lived Intangible Assets [Line Items]
Useful lives	26 years 4 months	27 years
Rights-of-way | Minimum
Finite-Lived Intangible Assets [Line Items]
Useful lives	20 years
Rights-of-way | Maximum
Finite-Lived Intangible Assets [Line Items]
Useful lives	30 years

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes and EPS (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	May 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Policies [Line Items]
Deferred tax liability, noncurrent			$ 0.6	$ 1.6
General partner
Significant Accounting Policies [Line Items]
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%

XML

SEGMENT INFORMATION - Assets by Reportable Segment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Assets	$ 3,164,672	$ 3,242,462	$ 2,282,046
Reportable Segments
Segment Reporting Information [Line Items]
Assets	3,142,382	3,211,249	2,262,765
Reportable Segments | Utica Shale Segment
Segment Reporting Information [Line Items]
Assets	886,224	735,587	0
Reportable Segments | Williston Basin Segment
Segment Reporting Information [Line Items]
Assets	740,361	861,461	680,014
Reportable Segments | Piceance DJ Basins Segment
Segment Reporting Information [Line Items]
Assets	866,095	941,382	936,794
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Assets	416,586	428,935	431,578
Reportable Segments | Marcellus Shale Segment
Segment Reporting Information [Line Items]
Assets	233,116	243,884	214,379
Corporate
Segment Reporting Information [Line Items]
Assets	$ 22,290	$ 31,213	$ 19,281

XML

SEGMENT INFORMATION - Revenues, Depreciation and Amortization, and Capital Expenditures by Reportable Segment (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 112,414	$ 115,201	$ 86,855	$ 86,087	$ 114,252	$ 94,152	$ 93,063	$ 85,702	$ 400,557	$ 387,169	$ 326,160
Depreciation and amortization									105,903	91,822	72,264
Capital expenditures									272,225	343,380	249,626
Reportable Segments
Segment Reporting Information [Line Items]
Revenues									400,557	387,169	326,160
Depreciation and amortization									105,300	91,235	71,813
Capital expenditures									271,796	342,920	248,696
Reportable Segments | Utica Shale Segment
Segment Reporting Information [Line Items]
Revenues									4,700	190	0
Depreciation and amortization									1,417	0	0
Capital expenditures									94,994	24,787	0
Reportable Segments | Williston Basin Segment
Segment Reporting Information [Line Items]
Revenues									98,929	109,807	81,501
Depreciation and amortization									31,376	24,027	16,669
Capital expenditures									147,477	227,283	129,236
Reportable Segments | Piceance DJ Basins Segment
Segment Reporting Information [Line Items]
Revenues									180,418	161,477	129,747
Depreciation and amortization									47,433	42,959	36,185
Capital expenditures									21,144	42,417	88,104
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Revenues									88,042	93,001	105,324
Depreciation and amortization									16,392	16,601	14,961
Capital expenditures									6,875	14,567	29,534
Reportable Segments | Marcellus Shale Segment
Segment Reporting Information [Line Items]
Revenues									28,468	22,694	9,588
Depreciation and amortization									8,682	7,648	3,998
Capital expenditures									1,306	33,866	1,822
Corporate
Segment Reporting Information [Line Items]
Depreciation and amortization									603	587	451
Capital expenditures									$ 429	$ 460	$ 930

XML

SEGMENT INFORMATION - Concentration Risk (Details) - Revenue - Customer concentration	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Counterparty A - Piceance
Segment Reporting Information [Line Items]
Concentration risk, percentage	16.00%	18.00%	19.00%
Counterparty B - Piceance
Segment Reporting Information [Line Items]
Concentration risk, percentage	14.00%	10.00%	10.00%
Counterparty C - Barnett Shale
Segment Reporting Information [Line Items]
Concentration risk, percentage	10.00%	10.00%	14.00%

XML

SEGMENT INFORMATION - Adjusted EBITDA by Reportable Segment (Details) - Reportable Segments - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 262,843	$ 223,416	$ 172,843
Utica Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	35,873	6,176	0
Williston Basin Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	34,008	30,009	17,350
Piceance DJ Basins Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	110,222	110,763	79,687
Barnett Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	59,526	60,528	69,473
Marcellus Shale Segment
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 23,214	$ 15,940	$ 6,333

XML

SEGMENT INFORMATION - Reconciliation of Net Income to Adjusted EBITDA (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Income before income taxes				$ (216,268)	$ (29,802)	$ 47,737
Add:
Interest expense				59,092	48,586	21,314
Depreciation and amortization				105,903	91,822	72,264
Proportional adjusted EBITDA for equity method investees				33,667	6,006	0
Adjustments related to MVC shortfall payments				(11,902)	26,565	17,025
Unit-based compensation				7,017	5,841	4,242
Loss on asset sales				42	442	113
Long-lived asset impairment	$ 1,600	$ 7,700	$ 5,500	9,305	5,505	0
Goodwill impairment	$ 248,900		$ 54,200	248,851	54,199	0
Less:
Interest income				2	4	5
Gain on asset sales				214	0	0
Impact of purchase price adjustment				0	1,185	0
Corporate
Add:
Allocated corporate expenses				27,352	15,441	10,153
Depreciation and amortization				603	587	451
Reportable Segments
Add:
Depreciation and amortization				105,300	91,235	71,813
Adjustments related to MVC shortfall payments				(11,902)	26,565	17,025
Less:
Total reportable segment adjusted EBITDA				$ 262,843	$ 223,416	$ 172,843

XML

SEGMENT INFORMATION - Adjustments Related to MVC Shortfall Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	$ (11,902)	$ 26,565	$ 17,025
Reportable Segments
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	(11,902)	26,565	17,025
Reportable Segments | Williston Basin Segment
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	11,870	10,743	3,600
Reportable Segments | Piceance DJ Basins Segment
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	(21,590)	15,194	12,395
Reportable Segments | Barnett Shale Segment
Segment Reporting Information [Line Items]
Adjustments related to MVC shortfall payments	$ (2,182)	$ 628	$ 1,030

XML

PROPERTY, PLANT, AND EQUIPMENT, NET (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Gross	$ 2,001,753		$ 1,748,182	$ 2,001,753	$ 1,748,182
Less accumulated depreciation	188,970		125,542	188,970	125,542
Property, plant, and equipment, net	1,812,783		1,622,640	1,812,783	1,622,640
Long-lived asset impairment	1,600	$ 7,700	5,500	9,305	5,505	$ 0
Depreciation expense				63,915	53,064	37,947
Capitalized interest				3,372	4,646	6,690
Williston Basin Segment
Property, Plant and Equipment [Line Items]
Long-lived asset impairment				7,554	0	0
Barnett Shale Segment
Property, Plant and Equipment [Line Items]
Long-lived asset impairment				531	5,505	0
Piceance Basin Segment
Property, Plant and Equipment [Line Items]
Long-lived asset impairment				1,220	0	$ 0
Gathering and processing systems and related equipment
Property, Plant and Equipment [Line Items]
Gross	1,883,139		1,630,250	1,883,139	1,630,250
Construction in progress
Property, Plant and Equipment [Line Items]
Gross	75,132		48,500	75,132	48,500
Land and line fill
Property, Plant and Equipment [Line Items]
Gross	11,055		11,057	11,055	11,057
Other
Property, Plant and Equipment [Line Items]
Gross	$ 32,427		$ 58,375	$ 32,427	$ 58,375

XML

AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Gross carrying amount	$ 600,802	$ 586,094
Accumulated amortization	(139,492)	(96,812)
Total intangible assets, net	$ 461,310	$ 489,282
Noncurrent liability
Unfavorable gas gathering contract, useful lives	10 years	10 years
Unfavorable contract, gross carrying amount	$ 10,962	$ 10,962
Unfavorable gas gathering contract, accumulated amortization	(6,077)	(5,385)
Unfavorable gas gathering contract, Net	4,885	5,577
Amortization expense
Amortization expense - unfavorable contract	692	$ 797	$ 1,046
Intangible assets
2016	43,108
2017	41,959
2018	41,413
2019	41,659
2020	44,305
Unfavorable gas gathering contract
2016	924
2017	1,047
2018	1,035
2019	1,045
2020	$ 834
Favorable gas gathering contract
Finite-Lived Intangible Assets [Line Items]
Useful lives	18 years 8 months 12 days	18 years 8 months 12 days
Gross carrying amount	$ 24,195	$ 24,195
Accumulated amortization	(9,534)	(8,056)
Total intangible assets, net	14,661	16,139
Amortization expense
Amortization expense	$ 1,478	$ 1,741	(2,078)
Contract intangibles
Finite-Lived Intangible Assets [Line Items]
Useful lives	12 years 6 months	12 years 6 months
Gross carrying amount	$ 426,464	$ 426,464
Accumulated amortization	(111,052)	(75,713)
Total intangible assets, net	315,412	350,751
Amortization expense
Amortization expense	$ 35,339	$ 32,554	28,654
Rights-of-way
Finite-Lived Intangible Assets [Line Items]
Useful lives	26 years 4 months	27 years
Gross carrying amount	$ 150,143	$ 135,435
Accumulated amortization	(18,906)	(13,043)
Total intangible assets, net	131,237	122,392
Amortization expense
Amortization expense	$ 5,863	$ 5,260	$ 4,631

XML

GOODWILL (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Roll Forward]
Goodwill, beginning balance			$ 265,062	$ 319,261
Goodwill impairment	$ (248,900)	$ (54,200)	(248,851)	(54,199)	$ 0
Goodwill, ending balance	16,211	265,062	16,211	265,062	319,261
Accumulated goodwill impairment	303,050	54,199	303,050	54,199	0
Piceance Basin Segment
Goodwill [Roll Forward]
Goodwill, beginning balance			45,478	45,478
Goodwill impairment			(45,478)	0
Goodwill, ending balance	0	45,478	0	45,478	45,478
Accumulated goodwill impairment	45,478	0	45,478	0	0
Williston Basin Segment
Goodwill [Roll Forward]
Goodwill, beginning balance			203,373	257,572
Goodwill impairment			(203,373)	(54,199)
Goodwill, ending balance	0	203,373	0	203,373	257,572
Accumulated goodwill impairment	257,572	54,199	257,572	54,199	0
Williston Basin Segment | Bison Midstream
Goodwill [Roll Forward]
Goodwill impairment		(54,200)
Marcellus Shale Segment
Goodwill [Roll Forward]
Goodwill, beginning balance			16,211	16,211
Goodwill impairment			0	0
Goodwill, ending balance	$ 16,211	$ 16,211	$ 16,211	$ 16,211	$ 16,211

XML

EQUITY METHOD INVESTMENTS (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	May 31, 2014	Jan. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Acquisition of initial interest in Ohio Gathering			$ 0	$ 190,000	$ 0
Ohio Gathering
Schedule of Equity Method Investments [Line Items]
Non-affiliated owners' interest percent	60.00%
Summit Midstream Partners, LLC | Ohio Gathering
Schedule of Equity Method Investments [Line Items]
Cost method ownership interest		1.00%
Ownership interest value		$ 190,000
Capital contribution		$ 8,400
Equity method potential ownership interest		40.00%
Equity method ownership interest	40.00%
Capital contributions true-ups	$ 326,600
Acquisition of initial interest in Ohio Gathering	50,400		$ 0	$ 190,000
Management fee	$ 5,400
Option value		$ 7,500

XML

EQUITY METHOD INVESTMENTS Rollforward of the Investment in Equity Method Investees (Details) - USD ($) $ in Thousands	1 Months Ended			12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	May 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investment [Roll Forward]
Investment in equity method investees, beginning of period				$ 706,172
Cash contributions				86,200	$ 145,131	$ 0
Cash distributions				(34,641)	(2,992)	0
Loss from equity method investees				(6,563)	(16,712)	0
Acquisition of initial interest in Ohio Gathering				0	190,000	0
January 2014 initial cash contribution				0	8,360	0
Option Exercise				0	382,385	0
Investment in equity method investees, end of period	$ 751,168	$ 706,172		751,168	706,172
Summit Midstream Partners, LLC | Ohio Gathering
Equity Method Investment [Roll Forward]
Investment in equity method investees, beginning of period	597,752	515,511		706,172	0
Cash contributions	3,472	0		86,200	145,131
Cash distributions	0	(20,420)		(34,641)	(2,992)
Loss from equity method investees				6,790	(4,472)
Amortization of basis difference in equity method investees	156,888	170,241		(13,353)	(12,240)
Acquisition of initial interest in Ohio Gathering			$ 50,400	0	190,000
January 2014 initial cash contribution				0	8,360
Option Exercise				0	382,385
Investment in equity method investees, end of period	$ 751,168	$ 706,172		$ 751,168	$ 706,172	$ 0

XML

EQUITY METHOD INVESTMENTS Balance Sheet Information (Details) - Summit Midstream Partners, LLC - Ohio Gathering - USD ($) $ in Thousands	Nov. 30, 2015	Nov. 30, 2014
Schedule of Equity Method Investments [Line Items]
Total assets	$ 1,510,075	$ 1,341,007
Total liabilities	59,313	95,391
Members' equity	$ 1,450,762	$ 1,245,616

XML

EQUITY METHOD INVESTMENTS Statements of Operations Information (Details) - USD ($) $ in Thousands	11 Months Ended
	Nov. 30, 2015	Nov. 30, 2014
Equity Method Investments and Joint Ventures [Abstract]
Total revenues	$ 130,090	$ 45,313
Total operating expenses	112,581	66,374
Net income (loss)	$ 16,803	$ (21,061)

XML

DEFERRED REVENUE (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		$ 2,377	$ 1,555
Additions		3,420	2,610
Less revenue recognized		5,120	1,788
Current deferred revenue, ending balance		677	2,377
Noncurrent deferred revenue, beginning balance		55,239	29,683
Additions		24,662	25,556
Less revenue recognized		34,415
Noncurrent deferred revenue, ending balance		45,486	55,239
Shortfall payments billed and included in accounts receivable		12,700
Williston Basin Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		0	0
Additions		0	0
Less revenue recognized		0	0
Current deferred revenue, ending balance		0	0
Noncurrent deferred revenue, beginning balance		17,132	6,389
Additions		11,897	10,743
Less revenue recognized		27
Noncurrent deferred revenue, ending balance		29,002	17,132
Barnett Shale Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		2,377	1,555
Additions		677	2,610
Less revenue recognized		2,377	1,788
Current deferred revenue, ending balance		677	2,377
Noncurrent deferred revenue, beginning balance		0	0
Additions		0	0
Less revenue recognized		0
Noncurrent deferred revenue, ending balance		0	0
Piceance Basin Segment
Movement in Deferred Revenue [Roll Forward]
Current deferred revenue, beginning balance		0	0
Additions		2,743	0
Less revenue recognized		2,743	0
Current deferred revenue, ending balance		0	0
Noncurrent deferred revenue, beginning balance		38,107	23,294
Additions		12,765	14,813
Less revenue recognized		34,388
Noncurrent deferred revenue, ending balance		$ 16,484	$ 38,107
Piceance Basin Segment | Gathering Services and Related Fees
Movement in Deferred Revenue [Roll Forward]
Less revenue recognized	$ 34,400

XML

DEBT - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Total long-term debt	$ 1,267,270	$ 1,232,207
Revolving credit facility
Line of Credit Facility [Line Items]
Revolving credit facility	$ 344,000	$ 208,000
Variable interest rate	2.93%	2.67%
5.5% Senior Notes
Line of Credit Facility [Line Items]
Senior unsecured notes	$ 295,861	$ 295,227
7.5% Senior Notes
Line of Credit Facility [Line Items]
Senior unsecured notes	294,909	293,980
Senior Notes | 5.5% Senior Notes
Line of Credit Facility [Line Items]
Long-term Debt, Gross	300,000	300,000
Deferred Finance Costs, Net	$ (4,139)	$ (4,773)
Stated interest rate	5.50%	5.50%
Senior Notes | 7.5% Senior Notes
Line of Credit Facility [Line Items]
Long-term Debt, Gross	$ 300,000	$ 300,000
Deferred Finance Costs, Net	$ (5,091)	$ (6,020)
Stated interest rate	7.50%	7.50%
SMP Holdings | Revolving credit facility
Line of Credit Facility [Line Items]
Revolving credit facility	$ 115,000	$ 35,000
Variable interest rate	2.43%	2.17%
SMP Holdings | Senior Secured Term Loan
Line of Credit Facility [Line Items]
Revolving credit facility	$ 217,500	$ 400,000
Effective interest rate	2.43%	2.17%

XML

DEBT - Maturities (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Debt
2016	$ 0
2017	217,500
2018	344,000
2019	115,000
2020	0
Thereafter	600,000
Total long-term debt	$ 1,276,500

XML

DEBT - Revolving Credit Facility (Details)		12 Months Ended
	Feb. 26, 2016 USD ($)	Dec. 31, 2015 USD ($)	Feb. 29, 2016 USD ($)	Dec. 31, 2014
Senior Notes
Line of Credit Facility [Line Items]
Debt defaults		$ 0
Subsequent Event | Senior Notes | Summit Holdings and Finance Corporation
Line of Credit Facility [Line Items]
Buy-back of debt, up to	$ 100,000,000
Revolving credit facility
Line of Credit Facility [Line Items]
Borrowing capacity		700,000,000
Accordion feature		$ 200,000,000.0
Commitment fee on unused portion of the facility (as a percent)		0.50%
Interest rate at period end		2.93%		2.67%
Unused portion under the facility		$ 356,000,000
Maximum cumulative lease payment obligations allowable under terms of covenants		$ 30,000,000.0
Period that cumulative lease payment obligations may not exceed specified amount under terms of covenants		12 months
Trailing period used in calculating the ratio of EBITDA to net interest expense		12 months
Ratio of consolidated EBITDA to net interest expense		2.5
Trailing period used in calculating the ratio of total indebtedness to consolidated EBITDA		12 months
Line of Credit Facility, Covenant, Senior Secured Leverage Ratio		3.75
Ratio of total indebtedness to consolidated EBITDA		5.0
Ratio of total indebtedness to consolidated EBITDA, for a specified period following certain acquisitions		5.5
Period following certain acquisitions, for which higher ratio of total indebtedness to consolidated EBITDA is to be maintained		270 days
Total leverage ratio		5.5
Debt defaults		$ 0
Revolving credit facility | Subsequent Event
Line of Credit Facility [Line Items]
Borrowing capacity			$ 1,250,000,000.00
Revolving credit facility | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		2.50%
Revolving credit facility | Minimum
Line of Credit Facility [Line Items]
Commitment fee on unused portion of the facility (as a percent)		0.30%
Revolving credit facility | Minimum | ABR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		0.75%
Revolving credit facility | Minimum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		1.75%
Revolving credit facility | Maximum
Line of Credit Facility [Line Items]
Commitment fee on unused portion of the facility (as a percent)		0.50%
Revolving credit facility | Maximum | ABR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		1.75%
Revolving credit facility | Maximum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin (as a percent)		2.75%

XML

DEBT - Senior Notes (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jul. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2013
Senior Notes
Debt Instrument [Line Items]
Debt defaults		$ 0
5.5% Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes		$ 295,861,000	$ 295,227,000
5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate		5.50%	5.50%
Debt issuance costs	$ 5,100,000
Events of default, period of payment default		30 days
Events of default, failure to comply with covenants, period after notice		180 days
Events of default, failure to comply with other agreements in the indenture, period after notice		30 days
Events of default, failure to pay final judgments, in excess of 20.0 million		$ 20,000,000
Declaration of immediate payment, holding percent of principal amount required		25.00%
7.5% Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes		$ 294,909,000	$ 293,980,000
7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Stated interest rate		7.50%	7.50%
Summit Holdings and Finance Corporation | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes	$ 300,000,000
Stated interest rate	5.50%
Maximum percent of aggregate principal amount redeemable		35.00%
Summit Holdings and Finance Corporation | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Senior unsecured notes				$ 300,000,000
Stated interest rate		7.50%		7.50%
Maximum percent of aggregate principal amount redeemable		35.00%
Debt issuance costs		$ 7,400,000
Events of default, period of payment default		30 days
Events of default, failure to comply with covenants, period after notice		180 days
Events of default, failure to comply with other agreements in the indenture, period after notice		30 days
Events of default, failure to pay final judgments, in excess of 20.0 million		$ 20,000,000
Declaration of immediate payment, holding percent of principal amount required		25.00%
Debt defaults		$ 0
Summit Holdings and Finance Corporation | Prior to August 15, 2017 | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		105.50%
Summit Holdings and Finance Corporation | August 15, 2017 - August 15, 2020 | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		104.125%
Summit Holdings and Finance Corporation | August 15, 2020 | 5.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		100.00%
Summit Holdings and Finance Corporation | Prior to July 1, 2016 | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		107.50%
Summit Holdings and Finance Corporation | July 1, 2016 - June 30, 2019 | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		105.625%
Summit Holdings and Finance Corporation | July 1, 2019 | 7.5% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount		100.00%
Summit Holdings | Finance Corp.
Debt Instrument [Line Items]
Cumulative percentage ownership in subsidiary	100.00%

XML

DEBT - SMP Holdings Credit Facility (Details)	1 Months Ended					12 Months Ended
	May 31, 2015 USD ($)	May 31, 2014 USD ($)	Mar. 31, 2014 USD ($)	Feb. 28, 2014 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Debt Instrument [Line Items]
Repayments under term loan						$ 182,500,000	$ 100,000,000	$ 100,000,000
Write-off of debt issuance costs						727,000	1,554,000	0
Borrowings under term loan						0	$ 400,000,000	$ 200,000,000
Revolving credit facility
Debt Instrument [Line Items]
Borrowing capacity						$ 700,000,000
Commitment fee on unused portion of the facility (as a percent)						0.50%
Ratio of total indebtedness to consolidated EBITDA						5.0
Ratio of total indebtedness to consolidated EBITDA, for a specified period following certain acquisitions						5.5
Period following certain acquisitions, for which higher ratio of total indebtedness to consolidated EBITDA is to be maintained						270 days
Revolving credit facility | LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)						2.50%
SMP Holdings | SMP Holdings Credit Facility
Debt Instrument [Line Items]
Decrease in basis spread on variable rate				0.75%
Commitment fee on unused portion of the facility (as a percent)					0.50%
Ratio of total indebtedness to consolidated EBITDA				5.0	4.0
Ratio of total indebtedness to consolidated EBITDA, for a specified period following certain acquisitions				5.5	5.0
Period following certain acquisitions, for which higher ratio of total indebtedness to consolidated EBITDA is to be maintained				270 days
Write-off of debt issuance costs			$ 1,500,000
SMP Holdings | Senior Secured Term Loan | SMP Holdings Credit Facility
Debt Instrument [Line Items]
Debt face amount					$ 200,000,000.0
Debt instrument, accordion amount				$ 400,000,000
Repayments under term loan	$ 175,000,000		100,000,000
Write-off of debt issuance costs	$ 700,000
Borrowings under term loan		$ 400,000,000
SMP Holdings | Revolving credit facility | SMP Holdings Credit Facility
Debt Instrument [Line Items]
Borrowing capacity				250,000,000.0	$ 150,000,000.0
Line of credit, accordion amount				$ 100,000,000
Repayments of lines of credit			$ 95,000,000
Minimum | Revolving credit facility
Debt Instrument [Line Items]
Commitment fee on unused portion of the facility (as a percent)						0.30%
Minimum | Revolving credit facility | LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)						1.75%
Minimum | Revolving credit facility | ABR
Debt Instrument [Line Items]
Applicable margin (as a percent)						0.75%
Minimum | SMP Holdings | SMP Holdings Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused portion of the facility (as a percent)				0.30%
Minimum | SMP Holdings | SMP Holdings Credit Facility | LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)				2.00%	2.75%
Minimum | SMP Holdings | SMP Holdings Credit Facility | ABR
Debt Instrument [Line Items]
Applicable margin (as a percent)				1.00%	1.75%
Maximum | Revolving credit facility
Debt Instrument [Line Items]
Commitment fee on unused portion of the facility (as a percent)						0.50%
Maximum | Revolving credit facility | LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)						2.75%
Maximum | Revolving credit facility | ABR
Debt Instrument [Line Items]
Applicable margin (as a percent)						1.75%
Maximum | SMP Holdings | SMP Holdings Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused portion of the facility (as a percent)				0.50%
Maximum | SMP Holdings | SMP Holdings Credit Facility | LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)				3.00%	3.75%
Maximum | SMP Holdings | SMP Holdings Credit Facility | ABR
Debt Instrument [Line Items]
Applicable margin (as a percent)				2.00%	2.75%

XML

FINANCIAL INSTRUMENTS - Concentration Risk (Details) - Accounts receivable - Customer concentration - customer	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
CONCENTRATIONS OF RISK
Concentration risk, number	5
Concentration risk, percentage	68.00%	57.00%

XML

FINANCIAL INSTRUMENTS - Fair value of Debt Instruments (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 1,276,500,000
Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Estimated fair value (Level 2)	344,000,000	$ 208,000,000
5.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Carrying value	295,861,000	295,227,000
5.5% Senior Notes | Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Estimated fair value (Level 2)	224,000,000	281,750,000
7.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Carrying value	294,909,000	293,980,000
7.5% Senior Notes | Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior notes, Estimated fair value (Level 2)	257,000,000	306,750,000
Revolving credit facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Carrying value	344,000,000	208,000,000
SMP Holdings | Senior Secured Term Loan
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	217,500,000	400,000,000
SMP Holdings | Senior Secured Term Loan | Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	217,500,000	400,000,000
SMP Holdings | Revolving credit facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Carrying value	115,000,000	35,000,000
SMP Holdings | Revolving credit facility | Senior Secured Term Loan
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Carrying value	115,000,000	35,000,000
SMP Holdings | Revolving credit facility | Senior Secured Term Loan | Fair value, Level 2 inputs
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving credit facility, Estimated fair value (Level 2)	115,000,000	$ 35,000,000
Senior Notes | 5.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt face amount	300,000,000
Senior Notes | 7.5% Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt face amount	$ 300,000,000

XML

PARTNERS' CAPITAL - Partners' Capital and Schedule of Units (Details) - $ / shares		1 Months Ended			12 Months Ended
	May 22, 2015	May 31, 2015	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Rollforwards of the number of partner units
Units, beginning balance					60,037,014	54,581,169	49,818,597
Units issued in connection with offering					7,627,551	5,408,337
Net units issued under SMLP LTIP					162,629	47,508	5,892
Units, ending balance					67,827,194	60,037,014	54,581,169
General partner
Class of Stock [Line Items]
Percentage interest in distributions					2.00%
Rollforwards of the number of partner units
General partner interest (as a percent)		2.00%		2.00%	2.00%	2.00%	2.00%
Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							1,585,560
Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							3,171,120
Common
Rollforwards of the number of partner units
Units, beginning balance					34,426,513	29,079,866	24,412,427
Units issued in connection with offering					7,475,000	5,300,000
Net units issued under SMLP LTIP					161,131	46,647	5,892
Units, ending balance					42,062,644	34,426,513	29,079,866
Common | Summit Investments
Rollforwards of the number of partner units
Common units sold in public offering			4,347,826
Common | Public Offering
Rollforwards of the number of partner units
Common units sold in public offering		6,500,000		10,350,000
Common units sold in public offering, price per share (in dollars per share)		$ 30.75		$ 38.75
Common | Public Offering | SMLP
Rollforwards of the number of partner units
Common units sold in public offering				5,300,000
Common | Public Offering | Summit Investments
Rollforwards of the number of partner units
Common units sold in public offering				5,050,000
Common | Over-Allotment Option
Rollforwards of the number of partner units
Common units sold in public offering	975,000
Common units sold in public offering, price per share (in dollars per share)	$ 30.75
Common | Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							1,553,849
Common | Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							3,107,698
Subordinated
Rollforwards of the number of partner units
Units, beginning balance					24,409,850	24,409,850	24,409,850
Units issued in connection with offering					0	0
Net units issued under SMLP LTIP					0	0	0
Units, ending balance					24,409,850	24,409,850	24,409,850
Subordinated | Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							0
Subordinated | Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							0
General partner
Rollforwards of the number of partner units
Units, beginning balance					1,200,651	1,091,453	996,320
Units issued in connection with offering					152,551	108,337
Net units issued under SMLP LTIP					1,498	861	0
Units, ending balance					1,354,700	1,200,651	1,091,453
General partner | Bison Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							31,711
General partner | Mountaineer Midstream
Rollforwards of the number of partner units
Units issued to a subsidiary of Summit Investments in connection with acquisition							63,422

XML

PARTNERS' CAPITAL - Subordination (Details)	1 Months Ended		12 Months Ended
	May 31, 2015	Mar. 31, 2014	Dec. 31, 2015 $ / shares	Dec. 31, 2014	Dec. 31, 2013
General partner
Schedule of Partners' Capital [Line Items]
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%
Condition one
Schedule of Partners' Capital [Line Items]
Minimum quarterly distribution (in dollars per share)			$ 1.60
Term for condition to be met to end subordination period			3 years
Condition one | General partner
Schedule of Partners' Capital [Line Items]
General partner interest (as a percent)			2.00%
Subordinated units
Schedule of Partners' Capital [Line Items]
Common unit per subordinated unit upon conversion at end of subordination period			1

XML

PARTNERS' CAPITAL - Allocation of Capital Distributions and Contributions (Details) - USD ($) $ / shares in Units, $ in Thousands							1 Months Ended			11 Months Ended	12 Months Ended
	May 18, 2015	Mar. 18, 2014	Jun. 21, 2013	Jun. 04, 2013	Jun. 03, 2013	Feb. 15, 2013	May 31, 2015	Feb. 28, 2015	Mar. 31, 2014	Feb. 28, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Net investment											$ 0	$ 0
Partners' capital contribution											4,737	4,235	$ 2,229
Partners' capital distribution											(152,074)	(122,224)	(90,196)
Polar Midstream and Epping
Business Acquisition [Line Items]
Percent of membership interest acquired	100.00%
Liabilities incurred for acquisition	$ 92,500
Total consideration	285,677
Partners' capital contribution	130,367
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Percent of membership interest acquired		100.00%
Cost of acquired entity, cash paid		$ 305,000						$ 2,900		$ 307,900
Total consideration		307,941
Partners' capital distribution		(66,124)
Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, cash paid				$ 200,000
Liabilities incurred for acquisition				200,000
Total consideration				248,900
Partners' capital contribution				$ 56,535
Basis for determining number of units issued, assumed equity issuance					$ 50,000
Basis for determining number of units issued, period					5 years
Basis for determining number of units issued, weighted-average price (in dollars per share)					$ 31.53
Closing price (in dollars per unit)				$ 30.85
Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable			$ 100,000
Liabilities incurred for acquisition			110,000
Total consideration			210,000
Basis for determining number of units issued, assumed equity issuance					$ 100,000
Basis for determining number of units issued, period					5 years
Basis for determining number of units issued, weighted-average price (in dollars per share)					$ 31.53
General partner
Business Acquisition [Line Items]
Partners' capital contribution											4,737	4,235
Partners' capital distribution											$ (9,784)	$ (4,770)	$ (1,803)
General partner interest (as a percent)							2.00%		2.00%		2.00%	2.00%	2.00%
General partner | Polar Midstream and Epping
Business Acquisition [Line Items]
Partners' capital contribution	2,607
General partner | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Partners' capital distribution		1,323
General partner | Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable				$ 978
Number of shares issued for acquisition				31,711
Partners' capital contribution				$ 1,131
General partner | Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable			$ 2,000
Number of shares issued for acquisition			63,422
Limited partners, Common
Business Acquisition [Line Items]
Partners' capital distribution											$ (86,880)	$ (67,658)	$ (46,286)
Limited partners, Common | Polar Midstream and Epping
Business Acquisition [Line Items]
Partners' capital contribution	80,079
Limited partners, Common | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Partners' capital distribution		37,910
Limited partners, Common | Bison Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable				$ 47,936
Number of shares issued for acquisition				1,553,849
Partners' capital contribution				$ 28,558
Limited partners, Common | Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, equity interests issued and issuable			$ 98,000
Number of shares issued for acquisition			3,107,698
Limited partners, Subordinated
Business Acquisition [Line Items]
Partners' capital distribution											$ (55,410)	$ (49,796)	$ (42,107)
Limited partners, Subordinated | Polar Midstream and Epping
Business Acquisition [Line Items]
Partners' capital contribution	47,681
Limited partners, Subordinated | Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Partners' capital distribution		26,891
Limited partners, Subordinated | Bison Midstream
Business Acquisition [Line Items]
Partners' capital contribution				26,846
Summit Investments | Bison Midstream
Business Acquisition [Line Items]
Total consideration						$ 303,168
Polar Midstream and Epping | Summit Investments
Business Acquisition [Line Items]
Net investment	$ 416,044
Red Rock Gathering Company, LLC | Summit Investments
Business Acquisition [Line Items]
Net investment		$ 241,817
Bison Midstream
Business Acquisition [Line Items]
Net investment				$ 305,449

XML

PARTNERS' CAPITAL - Cash Distribution Policy and Minimum Quarterly Distribution (Details)	12 Months Ended
	Dec. 31, 2015 $ / shares
Equity [Abstract]
Maximum period following end of quarter to distribute all available cash	45 days
Minimum quarterly distributions (in dollars per share)	$ 0.40
Minimum annual distributions (in dollars per share)	$ 1.60

XML

PARTNERS' CAPITAL - Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Feb. 12, 2016	Jan. 21, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Distribution Made to Limited Partner [Line Items]
Per-unit distribution (in dollars per unit)			$ 2.270	$ 2.040	$ 1.725
Cash paid to unit holders			$ 152,074	$ 122,224	$ 90,196
Subsequent Event
Distribution Made to Limited Partner [Line Items]
Per-unit distribution (in dollars per unit)		$ 0.575
Cash paid to unit holders	$ 41,000

XML

PARTNERS' CAPITAL - Partnership Target Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Partnership Target Distributions [Line Items]
IDR payments	$ 6,743	$ 2,326	$ 0
Minimum quarterly distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	$ 0.40
Thereafter
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.60
Minimum | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.40
Minimum | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.46
Minimum | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.50
Maximum | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.46
Maximum | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	0.50
Maximum | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Target quarterly distribution per unit target amount (in dollars per unit)	$ 0.60
Unitholders | Minimum quarterly distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	98.00%
Unitholders | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	98.00%
Unitholders | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	85.00%
Unitholders | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	75.00%
Unitholders | Thereafter
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	50.00%
General partner
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	2.00%
Quarterly distributions per unit, incentive threshold	$ 0.46
General partner | Minimum quarterly distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	2.00%
General partner | First target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	2.00%
General partner | Second target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	15.00%
General partner | Third target distribution
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	25.00%
General partner | Thereafter
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions	50.00%
General partner | Maximum
Schedule of Partnership Target Distributions [Line Items]
Percentage interest in distributions in excess of incentive threshold	50.00%

XML

EARNINGS PER UNIT (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners	$ (217,999)	$ 21,196	$ 1,094	$ 99	$ (38,375)	$ 4,909	$ 3,235	$ 3,114	$ (195,610)	$ (27,117)	$ 42,549
(Loss) earnings per limited partner unit:
Antidilutive securities excluded from the calculation of diluted loss per common unit											0
Phantom Units
(Loss) earnings per limited partner unit:
Antidilutive securities excluded from the calculation of diluted loss per common unit									109,201	231,875
Common units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners									$ (125,437)	$ (16,324)	$ 23,227
Weighted-average units outstanding - basic									39,217,000	33,311,000	26,951,000
Effect of nonvested phantom units									0	0	150,000
Weighted-average units outstanding – diluted									39,217,000	33,311,000	27,101,000
(Loss) earnings per limited partner unit:
Diluted (in dollars per share)	$ (3.28)	$ 0.32	$ 0.05	$ 0.00	$ (0.65)	$ 0.08	$ 0.05	$ 0.08	$ (3.20)	$ (0.49)	$ 0.86
Subordinated Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income attributable to limited partners									$ (70,173)	$ (10,793)	$ 19,322
Weighted-average units outstanding - basic									24,410,000	24,410,000	24,410,000
Weighted-average units outstanding – diluted									24,410,000	24,410,000	24,410,000
(Loss) earnings per limited partner unit:
Diluted (in dollars per share)									$ (2.88)	$ (0.44)	$ 0.79

XML

UNIT-BASED AND NONCASH COMPENSATION - SMLP Long-Term Incentive Plan (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted-average grant date fair value
Unit-based compensation	$ 6,174	$ 4,696	$ 2,999
Phantom Units
Weighted-average grant date fair value
Award vesting period	3 years
Restricted Stock Units (RSUs)
Weighted-average grant date fair value
Award vesting period	4 years
SMLP LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units reserved for issuance	5,000,000.0
Units available for future issuance	4,400,000
Weighted-average grant date fair value
Unrecognized unit-based compensation	$ 5,500
Remaining vesting period	1 year 2 months
Forfeitures assumed in the determination of estimated compensation expense	0
SMLP LTIP | General and administrative expense
Weighted-average grant date fair value
Unit-based compensation	$ 6,174	$ 4,696	$ 2,999
SMLP LTIP | Phantom and Restricted Units
Phantom and Restricted Unit Activity
Nonvested units, beginning of period	336,202	283,682	131,558
Units granted			156,165
Unit vested		(61,917)
Nonvested units, end of period	379,911	336,202	283,682
Weighted-average grant date fair value
Nonvested, Weighted-average grant date fair value, beginning (in dollars per unit)	$ 30.61	$ 23.41	$ 20.00
Units granted, Weighted-average grant date fair value (in dollars per unit)			26.33
Units vested, Weighted-average grant date fair value (in dollars per unit)		25.33
Nonvested, Weighted-average grant date fair value, ending (in dollars per unit)	$ 31.13	$ 30.61	$ 23.41
SMLP LTIP | Phantom Units
Phantom and Restricted Unit Activity
Units granted	289,735	136,867
Unit vested	(229,497)
Units forfeited	(16,529)	(22,430)	(4,041)
Weighted-average grant date fair value
Units granted, Weighted-average grant date fair value (in dollars per unit)	$ 29.21	$ 42.32
Units vested, Weighted-average grant date fair value (in dollars per unit)	27.66
Units forfeited, Weighted-average grant date fair value (in dollars per unit)	$ 35.09	$ 25.56	$ 25.99

XML

UNIT-BASED AND NONCASH COMPENSATION - SMP Net Profits Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation	$ 6,174	$ 4,696	$ 2,999
SMP Net Profits Interests
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Portion of membership interests authorized for issuance, percent				7.50%
Award vesting period	5 years
Unit-based compensation	$ 800	$ 1,100	$ 1,200

XML

UNIT-BASED AND NONCASH COMPENSATION - DFW Net Profits Interests (Details) - DFW Net Profit Interests $ in Millions	7 Months Ended	12 Months Ended
	Apr. 30, 2013 USD ($) holder shares	Dec. 31, 2015 shares	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Portion of membership interests authorized for issuance, percent			5.00%
Award vesting period		4 years
Repurchase of DFW Net Profits Interest, number of holders | holder	7
Payment to acquire vested net profits interests | $	$ 12.2
Restricted units exchanged for unvested net profits interests	7,393
Remaining or outstanding interests		0

XML

RELATED-PARTY TRANSACTIONS (Details) - General partner - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operation and maintenance expense
RELATED-PARTY TRANSACTIONS
Expenses from transactions with related party	$ 25,050	$ 22,004	$ 15,095
General and administrative expense
RELATED-PARTY TRANSACTIONS
Expenses from transactions with related party	$ 26,193	$ 24,993	$ 21,084

XML

COMMITMENTS AND CONTINGENCIES - Rent Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Total rent expense related to operating leases	$ 2,395	$ 1,881	$ 1,616

XML

COMMITMENTS AND CONTINGENCIES - Environmental Matters (Details) - Meadowland Midstream Gathering System - USD ($)		12 Months Ended
	Jun. 19, 2015	Dec. 31, 2015	Dec. 31, 2014
Accrual for Environmental Loss Contingencies [Roll Forward]
Accrued environmental remediation, beginning balance		$ 30,000,000	$ 0
Payments made by affiliates		(13,136,000)
Payments made with proceeds from insurance policies		(25,000,000)
Additional accruals		21,800,000	30,000,000
Accrued environmental remediation, ending balance		13,664,000	$ 30,000,000
Principal Owner | North Dakota Industrial Commission Case
Accrual for Environmental Loss Contingencies [Roll Forward]
Fines and other fees sought	$ 2,500,000
Maximum | Principal Owner
Accrual for Environmental Loss Contingencies [Roll Forward]
Coverage from pollution liability insurance policy		25,000,000.0
Coverage from property and business interruption insurance policy		$ 200,000,000.0

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - 2016 Drop Down (Details) $ in Thousands	Mar. 03, 2016 USD ($)	Dec. 15, 2014 USD ($)	Feb. 15, 2013 USD ($)
Utica Shale Play | Principal Owner
Business Acquisition [Line Items]
Cost of acquired entity, purchase price		$ 25,200
Meadowlark Midstream Company, LLC | Principal Owner
Business Acquisition [Line Items]
Cost of acquired entity, purchase price			$ 25,376
Current assets			2,227
Property, plant, and equipment			18,795
Other noncurrent assets			4,354
Total assets acquired			25,376
Total liabilities assumed			0
Net identifiable assets acquired			$ 25,376
Drop Down Assets 2016 Acquisition | Subsequent Event
Business Acquisition [Line Items]
Initial payment	$ 360,000
Deferred Purchase price obligation, multiple	6.5
Estimated future payment obligation	$ 860,300
Deferred purchase price obligation	$ 507,400
Discount rate	13.00%

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Polar and Divide Drop Down (Details) - USD ($) $ in Thousands, shares in Millions			1 Months Ended
	May 18, 2015	Feb. 15, 2013	Jul. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Values of Assets Acquired and Liabilities Assumed:
Goodwill				$ 16,211	$ 265,062	$ 319,261
Polar Midstream and Epping
Business Acquisition [Line Items]
Total consideration	$ 285,677
Liabilities incurred for acquisition	92,500
Cash payment for working capital and capital expenditure adjustments			$ 4,300
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price	$ 285,677
Polar Midstream and Epping | Common units
Business Acquisition [Line Items]
Number of shares issued for acquisition	193.4
Polar Midstream and Epping | General Partner Units
Business Acquisition [Line Items]
Number of shares issued for acquisition	4.1
Polar Midstream and Epping | Previously Reported
Business Acquisition [Line Items]
Total consideration	$ 290,000
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price	$ 290,000
Polar Midstream | Summit Investments
Business Acquisition [Line Items]
Total consideration		$ 216,105
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price		216,105
Current assets		368
Property, plant, and equipment		9,755
Other noncurrent assets		7,201
Total assets acquired		17,324
Current liabilities		4,592
Total liabilities assumed		4,592
Net identifiable assets acquired		12,732
Goodwill		$ 203,373

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Red Rock Gathering (Details) - USD ($) $ in Thousands		1 Months Ended		11 Months Ended	12 Months Ended
	Mar. 18, 2014	Feb. 28, 2015	Mar. 31, 2014	Feb. 28, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Purchase accounting adjustments					$ 0	$ 1,185	$ 0
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Cost of acquired entity, cash paid	$ 305,000	$ 2,900		$ 307,900
Purchase accounting adjustments						$ 1,200
Red Rock Gathering Company, LLC | Revolving credit facility
Business Acquisition [Line Items]
Borrowings incurred for acquisition			$ 100,000

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Lonestar Assets (Details) - Barnett Shale Play $ in Millions	Sep. 30, 2014 USD ($) contract
Property, Plant and Equipment [Line Items]
Payments to acquire gas gathering assets | $	$ 10.9
Number of long-term, fee-based contracts | contract	2

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Bison Midstream (Details) - USD ($) $ in Thousands			12 Months Ended
	Jun. 04, 2013	Feb. 15, 2013	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Fair Values of Assets Acquired and Liabilities Assumed:
Goodwill			$ 16,211	$ 319,261	$ 265,062
Gas Gathering Contract | Maximum
Business Acquisition [Line Items]
Useful lives			25 years
Bison Midstream
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price	$ 248,900
Cost of acquired entity, cash paid	200,000
Liabilities incurred for acquisition	200,000
Purchase price assigned to Bison Gas Gathering system				$ 303,168
Bison Midstream | Common units
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, equity interests issued and issuable	47,900
Bison Midstream | General Partner Units
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, equity interests issued and issuable	1,000
Purchase price assigned to Bison Gas Gathering system	$ 303,200
Bison Midstream | Summit Investments
Fair Values of Assets Acquired and Liabilities Assumed:
Cost of acquired entity, purchase price		$ 303,168
Current assets		5,705
Property, plant, and equipment		85,477
Intangible assets		164,502
Other noncurrent assets		2,187
Total assets acquired		257,871
Current liabilities		6,112
Other noncurrent liabilities		2,790
Total liabilities assumed		8,902
Net identifiable assets acquired		248,969
Goodwill		$ 54,199
Bison Midstream | Gas Gathering Contract | Minimum
Business Acquisition [Line Items]
Useful lives			5 years
Bison Midstream | Gas Gathering Contract | Maximum
Business Acquisition [Line Items]
Useful lives			15 years
Bison Midstream | Gas Gathering Contract | Weighted Average
Business Acquisition [Line Items]
Useful lives			12 years

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Mountaineer Midstream (Details) $ in Thousands		12 Months Ended
	Jun. 21, 2013 USD ($) compressor_station	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Fair Values of Assets Acquired and Liabilities Assumed:
Goodwill		$ 16,211	$ 265,062	$ 319,261
Contract intangibles
Business Acquisition [Line Items]
Useful lives		12 years 6 months	12 years 6 months
Mountaineer Midstream
Business Acquisition [Line Items]
Cost of acquired entity, purchase price	$ 210,000
Number of compressor stations acquired | compressor_station	2
Liabilities incurred for acquisition	$ 110,000
Cost of acquired entity, equity interests issued and issuable	100,000
Mountaineer Midstream revenues since acquisition				9,600
Mountaineer Midstream net income since acquisition				$ 2,300
Fair Values of Assets Acquired and Liabilities Assumed:
Property, plant, and equipment	163,661
Total assets acquired	193,789
Total liabilities assumed	0
Net identifiable assets acquired	193,789
Goodwill	16,211
Mountaineer Midstream | Gas gathering agreement contract intangibles
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	24,019
Mountaineer Midstream | Contract intangibles
Business Acquisition [Line Items]
Useful lives		13 years
Mountaineer Midstream | Rights-of-way
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	6,109
Mountaineer Midstream | Previously Reported
Fair Values of Assets Acquired and Liabilities Assumed:
Property, plant, and equipment	158,300
Goodwill	18,100
Mountaineer Midstream | Previously Reported | Contract intangibles
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	27,100
Mountaineer Midstream | Previously Reported | Rights-of-way
Fair Values of Assets Acquired and Liabilities Assumed:
Intangible assets	$ 6,500

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Revenue and Net Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$ 112,414	$ 115,201	$ 86,855	$ 86,087	$ 114,252	$ 94,152	$ 93,063	$ 85,702	$ 400,557	$ 387,169	$ 326,160
Net (loss) income									(222,228)	(47,368)	47,008
Summit Midstream Partners, LP
Business Acquisition [Line Items]
Revenues									358,046	338,941	241,089
Net (loss) income									(192,212)	(23,992)	43,584
Drop Down Assets 2016 Acquisition
Business Acquisition [Line Items]
Revenues									29,238	14,466	2,474
Net (loss) income									(35,419)	(32,634)	(5,829)
Polar Midstream and Epping
Business Acquisition [Line Items]
Revenues									13,273	22,449	3,893
Net (loss) income									$ 5,403	6,430	(467)
Red Rock Gathering Company, LLC
Business Acquisition [Line Items]
Revenues										11,313	50,114
Net (loss) income										$ 2,828	9,668
Bison Midstream
Business Acquisition [Line Items]
Revenues											28,590
Net (loss) income											$ 52

XML

ACQUISITIONS AND DROP DOWN TRANSACTIONS - Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended		12 Months Ended
	Mar. 03, 2016	May 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Borrowings under revolving credit facility				$ 367,000	$ 294,295	$ 476,950
Pro forma total revenues						338,311
Pro forma net income						$ 34,369
Limited partners, Common
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma EPU, basic and diluted (in dollars per share)						$ 0.68
Subordinated Units
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Pro forma EPU, basic and diluted (in dollars per share)						$ 0.62
Bison Midstream and Mountaineer Midstream
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Common unit issuance				4,661,547
Incremental borrowings on revolving credit facility						$ 310,000
Revenues included in consolidated revenues						87,196
Net income included in consolidated net income						(457)
Bison Midstream and Mountaineer Midstream | Acquisition-related costs
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Nonrecurring transaction cost						$ 2,500
General partner
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
General partner interest (as a percent)		2.00%	2.00%	2.00%	2.00%	2.00%
Revolving credit facility | Drop Down Assets 2016 Acquisition | Subsequent Event
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Borrowings under revolving credit facility	$ 360,000

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Condensed Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assets
Cash and cash equivalents	$ 21,793	$ 27,811	$ 25,784	$ 11,334
Accounts receivable	89,581	92,908
Insurance receivable	0	25,000
Due from affiliate	0	0
Other current assets	3,573	3,600
Total current assets	114,947	149,319
Property, plant and equipment, net	1,812,783	1,622,640
Intangible assets, net	461,310	489,282
Investment in equity method investees	751,168	706,172
Goodwill	16,211	265,062	319,261
Other noncurrent assets	8,253	9,987
Investment in subsidiaries	0	0
Total assets	3,164,672	3,242,462	2,282,046
Liabilities [Abstract]
Trade accounts payable	40,808	38,391
Due to affiliate	1,149	2,711
Deferred revenue	677	2,377	1,555
Ad valorem taxes payable	10,271	9,179
Accrued interest	17,483	18,858
Accrued environmental remediation	7,900	25,000
Other current liabilities	13,297	15,307
Total current liabilities	91,585	111,823
Long-term debt	1,267,270	1,232,207
Deferred revenue	45,486	55,239	29,683
Noncurrent accrued environmental remediation	5,764	5,000
Other noncurrent liabilities	7,268	7,515
Total liabilities	1,417,373	1,411,784
Total partners' capital	1,747,299	1,830,678	1,395,806	1,028,355
Total liabilities and partners' capital	3,164,672	3,242,462
SMLP
Assets
Cash and cash equivalents	73	7,531	6,291	5,056
Accounts receivable	0	0
Insurance receivable		0
Due from affiliate	3,168	764
Other current assets	540	907
Total current assets	3,781	9,202
Property, plant and equipment, net	1,178	1,351
Intangible assets, net	0	0
Investment in equity method investees	0	0
Goodwill	0	0
Other noncurrent assets	3,480	3,771
Investment in subsidiaries	2,438,395	2,419,433
Total assets	2,446,834	2,433,757
Liabilities [Abstract]
Trade accounts payable	482	1,144
Due to affiliate	360,243	163,565
Deferred revenue	0	0
Ad valorem taxes payable	9	23
Accrued interest	0	0
Accrued environmental remediation	0	0
Other current liabilities	4,558	1,622
Total current liabilities	365,292	166,354
Long-term debt	332,500	435,000
Deferred revenue	0	0
Noncurrent accrued environmental remediation	0	0
Other noncurrent liabilities	1,743	1,725
Total liabilities	699,535	603,079
Total partners' capital	1,747,299	1,830,678
Total liabilities and partners' capital	2,446,834	2,433,757
Co-Issuers
Assets
Cash and cash equivalents	12,407	11,621	125	170
Accounts receivable	0	0
Insurance receivable		0
Due from affiliate	151,443	63,239
Other current assets	0	0
Total current assets	163,850	74,860
Property, plant and equipment, net	0	0
Intangible assets, net	0	0
Investment in equity method investees	0	0
Goodwill	0	0
Other noncurrent assets	4,611	6,027
Investment in subsidiaries	3,222,187	3,154,626
Total assets	3,390,648	3,235,513
Liabilities [Abstract]
Trade accounts payable	0	0
Due to affiliate	0	0
Deferred revenue	0	0
Ad valorem taxes payable	0	0
Accrued interest	17,483	18,858
Accrued environmental remediation	0	0
Other current liabilities	0	15
Total current liabilities	17,483	18,873
Long-term debt	934,770	797,207
Deferred revenue	0	0
Noncurrent accrued environmental remediation	0	0
Other noncurrent liabilities	0	0
Total liabilities	952,253	816,080
Total partners' capital	2,438,395	2,419,433
Total liabilities and partners' capital	3,390,648	3,235,513
Guarantor subsidiaries
Assets
Cash and cash equivalents	6,930	7,353	13,942	6,108
Accounts receivable	84,021	89,201
Insurance receivable		0
Due from affiliate	207,651	97,615
Other current assets	2,672	2,610
Total current assets	301,274	196,779
Property, plant and equipment, net	1,462,623	1,412,998
Intangible assets, net	438,093	477,734
Investment in equity method investees	0	0
Goodwill	16,211	265,062
Other noncurrent assets	162	189
Investment in subsidiaries	0	0
Total assets	2,218,363	2,352,762
Liabilities [Abstract]
Trade accounts payable	18,489	23,711
Due to affiliate	0	0
Deferred revenue	677	2,377
Ad valorem taxes payable	9,881	9,095
Accrued interest	0	0
Accrued environmental remediation	0	0
Other current liabilities	7,405	12,552
Total current liabilities	36,452	47,735
Long-term debt	0	0
Deferred revenue	45,486	55,239
Noncurrent accrued environmental remediation	0	0
Other noncurrent liabilities	5,503	5,790
Total liabilities	87,441	108,764
Total partners' capital	2,130,922	2,243,998
Total liabilities and partners' capital	2,218,363	2,352,762
Non-guarantor subsidiaries
Assets
Cash and cash equivalents	2,383	1,306	5,426	0
Accounts receivable	5,560	3,707
Insurance receivable		25,000
Due from affiliate	0	0
Other current assets	361	83
Total current assets	8,304	30,096
Property, plant and equipment, net	348,982	208,291
Intangible assets, net	23,217	11,548
Investment in equity method investees	751,168	706,172
Goodwill	0	0
Other noncurrent assets	0	0
Investment in subsidiaries	0	0
Total assets	1,131,671	956,107
Liabilities [Abstract]
Trade accounts payable	21,837	13,536
Due to affiliate	3,168	764
Deferred revenue	0	0
Ad valorem taxes payable	381	61
Accrued interest	0	0
Accrued environmental remediation	7,900	25,000
Other current liabilities	1,334	1,118
Total current liabilities	34,620	40,479
Long-term debt	0	0
Deferred revenue	0	0
Noncurrent accrued environmental remediation	5,764	5,000
Other noncurrent liabilities	22	0
Total liabilities	40,406	45,479
Total partners' capital	1,091,265	910,628
Total liabilities and partners' capital	1,131,671	956,107
Consolidating adjustments
Assets
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable	0	0
Insurance receivable		0
Due from affiliate	(362,262)	(161,618)
Other current assets	0	0
Total current assets	(362,262)	(161,618)
Property, plant and equipment, net	0	0
Intangible assets, net	0	0
Investment in equity method investees	0	0
Goodwill	0	0
Other noncurrent assets	0	0
Investment in subsidiaries	(5,660,582)	(5,574,059)
Total assets	(6,022,844)	(5,735,677)
Liabilities [Abstract]
Trade accounts payable	0	0
Due to affiliate	(362,262)	(161,618)
Deferred revenue	0	0
Ad valorem taxes payable	0	0
Accrued interest	0	0
Accrued environmental remediation	0	0
Other current liabilities	0	0
Total current liabilities	(362,262)	(161,618)
Long-term debt	0	0
Deferred revenue	0	0
Noncurrent accrued environmental remediation	0	0
Other noncurrent liabilities	0	0
Total liabilities	(362,262)	(161,618)
Total partners' capital	(5,660,582)	(5,574,059)
Total liabilities and partners' capital	$ (6,022,844)	$ (5,735,677)

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Condensed Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Gathering services and related fees									$ 337,819	$ 267,478	$ 216,352
Natural gas, NGLs and condensate sales									42,079	97,094	88,185
Other revenues									20,659	22,597	21,623
Total revenues	$ 112,414	$ 115,201	$ 86,855	$ 86,087	$ 114,252	$ 94,152	$ 93,063	$ 85,702	400,557	387,169	326,160
Costs and expenses:
Cost of natural gas and NGLs									31,398	72,415	68,037
Operation and maintenance									94,986	94,869	78,175
General and administrative									45,108	43,281	36,716
Transaction costs									1,342	2,985	2,841
Depreciation and amortization									105,117	90,878	71,232
Environmental remediation									21,800	5,000	0
Loss on asset sales, net									(172)	442	113
Long-lived asset impairment	1,600	$ 7,700			5,500				9,305	5,505	0
Goodwill impairment	$ 248,900				$ 54,200				248,851	54,199	0
Total costs and expenses									557,735	369,574	257,114
Other income									2	1,189	5
Interest expense									(59,092)	(48,586)	(21,314)
(Loss) income before income taxes									(216,268)	(29,802)	47,737
Income tax expense									603	(854)	(729)
Loss from equity method investees									(6,563)	(16,712)	0
Equity in loss of consolidated subsidiaries									0	0	0
Net (loss) income									(222,228)	(47,368)	47,008
Co-Issuers
Revenues:
Gathering services and related fees									0	0	0
Natural gas, NGLs and condensate sales									0	0	0
Other revenues									0	0	0
Total revenues									0	0	0
Costs and expenses:
Cost of natural gas and NGLs									0	0	0
Operation and maintenance									0	0	0
General and administrative									0	0	0
Transaction costs									0	0	0
Depreciation and amortization									0	0	0
Environmental remediation									0	0
Loss on asset sales, net									0	0	0
Long-lived asset impairment									0	0
Goodwill impairment									0	0
Total costs and expenses									0	0	0
Other income									0	0	0
Interest expense									(48,598)	(40,169)	(19,173)
(Loss) income before income taxes									(48,598)	(40,169)	(19,173)
Income tax expense									0	0	0
Loss from equity method investees									0	0
Equity in loss of consolidated subsidiaries									(161,796)	6,471	71,612
Net (loss) income									(210,394)	(33,698)	52,439
Guarantor subsidiaries
Revenues:
Gathering services and related fees									310,830	255,211	213,979
Natural gas, NGLs and condensate sales									42,079	97,094	88,185
Other revenues									18,411	20,398	21,522
Total revenues									371,320	372,703	323,686
Costs and expenses:
Cost of natural gas and NGLs									31,398	72,415	68,037
Operation and maintenance									87,286	88,927	77,122
General and administrative									37,926	40,447	33,970
Transaction costs									0	0	0
Depreciation and amortization									95,586	86,762	70,122
Environmental remediation									0	0
Loss on asset sales, net									(172)	442	(113)
Long-lived asset impairment									9,305	5,505
Goodwill impairment									248,851	54,199
Total costs and expenses									510,180	348,697	249,364
Other income									0	1,189	0
Interest expense									0	0	0
(Loss) income before income taxes									(138,860)	25,195	74,322
Income tax expense									0	826	(729)
Loss from equity method investees									0	0
Equity in loss of consolidated subsidiaries									0	0	0
Net (loss) income									(138,860)	26,021	73,593
Non-guarantor subsidiaries
Revenues:
Gathering services and related fees									26,989	12,267	2,373
Natural gas, NGLs and condensate sales									0	0	0
Other revenues									2,248	2,199	101
Total revenues									29,237	14,466	2,474
Costs and expenses:
Cost of natural gas and NGLs									0	0	0
Operation and maintenance									7,700	5,942	1,053
General and administrative									7,182	2,834	2,746
Transaction costs									0	0	0
Depreciation and amortization									8,928	3,528	656
Environmental remediation									21,800	5,000
Loss on asset sales, net									0	0	0
Long-lived asset impairment									0	0
Goodwill impairment									0	0
Total costs and expenses									45,610	17,304	4,455
Other income									0	0	0
Interest expense									0	0	0
(Loss) income before income taxes									(16,373)	(2,838)	(1,981)
Income tax expense									0	0	0
Loss from equity method investees									(6,563)	(16,712)
Equity in loss of consolidated subsidiaries									0	0	0
Net (loss) income									(22,936)	(19,550)	(1,981)
SMLP
Revenues:
Gathering services and related fees									0	0	0
Natural gas, NGLs and condensate sales									0	0	0
Other revenues									0	0	0
Total revenues									0	0	0
Costs and expenses:
Cost of natural gas and NGLs									0	0	0
Operation and maintenance									0	0	0
General and administrative									0	0	0
Transaction costs									1,342	2,985	2,841
Depreciation and amortization									603	588	454
Environmental remediation									0	0
Loss on asset sales, net									0	0	0
Long-lived asset impairment									0	0
Goodwill impairment									0	0
Total costs and expenses									1,945	3,573	3,295
Other income									2	0	5
Interest expense									(10,494)	(8,417)	(2,141)
(Loss) income before income taxes									(12,437)	(11,990)	(5,431)
Income tax expense									603	(1,680)	0
Loss from equity method investees									0	0
Equity in loss of consolidated subsidiaries									(210,394)	(33,698)	52,439
Net (loss) income									(222,228)	(47,368)	47,008
Consolidating adjustments
Revenues:
Gathering services and related fees									0	0	0
Natural gas, NGLs and condensate sales									0	0	0
Other revenues									0	0	0
Total revenues									0	0	0
Costs and expenses:
Cost of natural gas and NGLs									0	0	0
Operation and maintenance									0	0	0
General and administrative									0	0	0
Transaction costs									0	0
Depreciation and amortization									0	0	0
Environmental remediation									0	0
Loss on asset sales, net									0	0	0
Long-lived asset impairment									0	0
Goodwill impairment									0	0
Total costs and expenses									0	0	0
Other income									0	0	0
Interest expense									0	0	0
(Loss) income before income taxes									0	0	0
Income tax expense									0	0	0
Loss from equity method investees									0	0
Equity in loss of consolidated subsidiaries									372,190	27,227	(124,051)
Net (loss) income									$ 372,190	$ 27,227	$ (124,051)

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Condensed Cash Flow Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 191,375	$ 152,953	$ 135,411
Cash flows from investing activities:
Capital expenditures	(272,225)	(343,380)	(249,626)
Initial contribution to Ohio Gathering	0	(8,360)	0
Acquisition of Ohio Gathering Option	0	(190,000)	0
Option Exercise	0	(382,385)	0
Contributions to equity method investees	(86,200)	(145,131)	0
Proceeds from asset sales	323	325	585
Payments to Acquire Productive Assets	0	(10,872)	(210,000)
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618)	(305,000)	(200,000)
Advances to affiliates	0	0	0
Net cash used in investing activities	(646,720)	(1,384,803)	(659,041)
Cash flows from financing activities:
Distributions to unitholders	(152,074)	(122,224)	(90,196)
Borrowings under revolving credit facility	367,000	294,295	476,950
Repayments under revolving credit facility	(151,000)	(430,295)	(297,180)
Borrowings under term loan	0	400,000	200,000
Repayments under term loan	(182,500)	(100,000)	(100,000)
Deferred loan costs	(412)	(8,323)	(14,059)
Proceeds from issuance of common units, net	221,977	197,806	0
Contribution from general partner	4,737	4,235	2,229
Cash advance from Summit Investments to contributed subsidiaries, net	320,527	674,383	(50,087)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	22,879	24,884	22,380
Issuance of senior notes	0	300,000	300,000
Repurchase of equity-based compensation awards	0	(228)	(11,957)
Issuance of units to affiliate in connection with the Mountaineer Acquisition	0	0	100,000
Other, net	(1,807)	(656)	0
Advances from affiliates	0	0	0
Net cash provided by financing activities	449,327	1,233,877	538,080
Net change in cash and cash equivalents	(6,018)	2,027	14,450
Cash and cash equivalents, beginning of period	27,811	25,784	11,334
Cash and cash equivalents, end of period	21,793	27,811	25,784
SMLP
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	409	(3,658)	(544)
Cash flows from investing activities:
Capital expenditures	(429)	(460)	(930)
Initial contribution to Ohio Gathering		0
Acquisition of Ohio Gathering Option		0
Option Exercise		0
Contributions to equity method investees	0	0
Proceeds from asset sales	0	0	0
Payments to Acquire Productive Assets		0	(210,000)
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618)	(305,000)	(200,000)
Advances to affiliates	(2,589)	(183)	(84)
Net cash used in investing activities	(291,636)	(305,643)	(411,014)
Cash flows from financing activities:
Distributions to unitholders	(152,074)	(122,224)	(90,196)
Borrowings under revolving credit facility	180,000	57,000	96,000
Repayments under revolving credit facility	(100,000)	(115,000)	(3,000)
Borrowings under term loan		400,000	200,000
Repayments under term loan	(182,500)	(100,000)	(100,000)
Deferred loan costs	(135)	(3,003)	(3,451)
Proceeds from issuance of common units, net	221,977	197,806
Contribution from general partner	4,737	4,235	2,229
Cash advance from Summit Investments to contributed subsidiaries, net	102,500	(242,000)	(193,000)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	12,655	12,845	8,088
Issuance of senior notes		0	0
Repurchase of equity-based compensation awards		(228)	(11,957)
Issuance of units to affiliate in connection with the Mountaineer Acquisition			100,000
Other, net	(1,615)	(656)
Advances from affiliates	198,224	221,766	408,080
Net cash provided by financing activities	283,769	310,541	412,793
Net change in cash and cash equivalents	(7,458)	1,240	1,235
Cash and cash equivalents, beginning of period	7,531	6,291	5,056
Cash and cash equivalents, end of period	73	7,531	6,291
Co-Issuers
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(46,716)	(30,689)	(4,799)
Cash flows from investing activities:
Capital expenditures	0	0	0
Initial contribution to Ohio Gathering		0
Acquisition of Ohio Gathering Option		0
Option Exercise		0
Contributions to equity method investees	0	0
Proceeds from asset sales	0	0	0
Payments to Acquire Productive Assets		0	0
Acquisitions of gathering systems from affiliate, net of acquired cash	0	0	0
Advances to affiliates	(88,221)	(174,495)	(371,408)
Net cash used in investing activities	(88,221)	(174,495)	(371,408)
Cash flows from financing activities:
Distributions to unitholders	0	0	0
Borrowings under revolving credit facility	187,000	237,295	380,950
Repayments under revolving credit facility	(51,000)	(315,295)	(294,180)
Borrowings under term loan		0	0
Repayments under term loan	0	0	0
Deferred loan costs	(277)	(5,320)	(10,608)
Proceeds from issuance of common units, net	0	0
Contribution from general partner	0	0	0
Cash advance from Summit Investments to contributed subsidiaries, net	0	0	0
Expenses paid by Summit Investments on behalf of contributed subsidiaries	0	0	0
Issuance of senior notes		300,000	300,000
Repurchase of equity-based compensation awards		0	0
Issuance of units to affiliate in connection with the Mountaineer Acquisition			0
Other, net	0	0
Advances from affiliates	0	0	0
Net cash provided by financing activities	135,723	216,680	376,162
Net change in cash and cash equivalents	786	11,496	(45)
Cash and cash equivalents, beginning of period	11,621	125	170
Cash and cash equivalents, end of period	12,407	11,621	125
Guarantor subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	202,324	179,685	141,260
Cash flows from investing activities:
Capital expenditures	(118,458)	(220,360)	(182,048)
Initial contribution to Ohio Gathering		0
Acquisition of Ohio Gathering Option		0
Option Exercise		0
Contributions to equity method investees	0	0
Proceeds from asset sales	323	325	585
Payments to Acquire Productive Assets		(10,872)	0
Acquisitions of gathering systems from affiliate, net of acquired cash	0	0	0
Advances to affiliates	(110,003)	(47,271)	(36,672)
Net cash used in investing activities	(228,138)	(278,178)	(218,135)
Cash flows from financing activities:
Distributions to unitholders	0	0	0
Borrowings under revolving credit facility	0	0	0
Repayments under revolving credit facility	0	0	0
Borrowings under term loan		0	0
Repayments under term loan	0	0	0
Deferred loan costs	0	0	0
Proceeds from issuance of common units, net	0	0
Contribution from general partner	0	0	0
Cash advance from Summit Investments to contributed subsidiaries, net	21,719	81,421	72,745
Expenses paid by Summit Investments on behalf of contributed subsidiaries	3,864	10,483	11,964
Issuance of senior notes		0	0
Repurchase of equity-based compensation awards		0	0
Issuance of units to affiliate in connection with the Mountaineer Acquisition			0
Other, net	(192)	0
Advances from affiliates	0	0	0
Net cash provided by financing activities	25,391	91,904	84,709
Net change in cash and cash equivalents	(423)	(6,589)	7,834
Cash and cash equivalents, beginning of period	7,353	13,942	6,108
Cash and cash equivalents, end of period	6,930	7,353	13,942
Non-guarantor subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	35,358	7,615	(506)
Cash flows from investing activities:
Capital expenditures	(153,338)	(122,560)	(66,648)
Initial contribution to Ohio Gathering		(8,360)
Acquisition of Ohio Gathering Option		(190,000)
Option Exercise		(382,385)
Contributions to equity method investees	(86,200)	(145,131)
Proceeds from asset sales	0	0	0
Payments to Acquire Productive Assets		0	0
Acquisitions of gathering systems from affiliate, net of acquired cash	0	0	0
Advances to affiliates	0	0	0
Net cash used in investing activities	(239,538)	(848,436)	(66,648)
Cash flows from financing activities:
Distributions to unitholders	0	0	0
Borrowings under revolving credit facility	0	0	0
Repayments under revolving credit facility	0	0	0
Borrowings under term loan		0	0
Repayments under term loan	0	0	0
Deferred loan costs	0	0	0
Proceeds from issuance of common units, net	0	0
Contribution from general partner	0	0	0
Cash advance from Summit Investments to contributed subsidiaries, net	196,308	834,962	70,168
Expenses paid by Summit Investments on behalf of contributed subsidiaries	6,360	1,556	2,328
Issuance of senior notes		0	0
Repurchase of equity-based compensation awards		0	0
Issuance of units to affiliate in connection with the Mountaineer Acquisition			0
Other, net	0	0
Advances from affiliates	2,589	183	84
Net cash provided by financing activities	205,257	836,701	72,580
Net change in cash and cash equivalents	1,077	(4,120)	5,426
Cash and cash equivalents, beginning of period	1,306	5,426	0
Cash and cash equivalents, end of period	2,383	1,306	5,426
Consolidating adjustments
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	0	0	0
Cash flows from investing activities:
Capital expenditures	0	0	0
Initial contribution to Ohio Gathering		0
Acquisition of Ohio Gathering Option		0
Option Exercise		0
Contributions to equity method investees	0	0
Proceeds from asset sales	0	0	0
Payments to Acquire Productive Assets		0	0
Acquisitions of gathering systems from affiliate, net of acquired cash	0	0	0
Advances to affiliates	200,813	221,949	408,164
Net cash used in investing activities	200,813	221,949	408,164
Cash flows from financing activities:
Distributions to unitholders	0	0	0
Borrowings under revolving credit facility	0	0	0
Repayments under revolving credit facility	0	0	0
Borrowings under term loan		0	0
Repayments under term loan	0	0	0
Deferred loan costs	0	0	0
Proceeds from issuance of common units, net	0	0
Contribution from general partner	0	0	0
Cash advance from Summit Investments to contributed subsidiaries, net	0	0	0
Expenses paid by Summit Investments on behalf of contributed subsidiaries	0	0	0
Issuance of senior notes		0	0
Repurchase of equity-based compensation awards		0	0
Issuance of units to affiliate in connection with the Mountaineer Acquisition			0
Other, net	0	0
Advances from affiliates	(200,813)	(221,949)	(408,164)
Net cash provided by financing activities	(200,813)	(221,949)	(408,164)
Net change in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	$ 0	$ 0	$ 0

XML

UNAUDITED QUARTERLY FINANCIAL DATA (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Limited Partners' Capital Account [Line Items]
Revenues	$ 112,414	$ 115,201	$ 86,855	$ 86,087	$ 114,252	$ 94,152	$ 93,063	$ 85,702	$ 400,557	$ 387,169	$ 326,160
Net (loss) income attributable to SMLP	(220,468)	23,604	2,985	1,667	(37,686)	6,113	4,036	3,545	(192,212)	(23,992)	43,584
Less net (loss) income attributable to general partner, including IDRs	(2,469)	2,408	1,891	1,568	689	1,204	801	431	3,398	3,125	1,035
Net (loss) income attributable to limited partners	(217,999)	21,196	$ 1,094	$ 99	(38,375)	$ 4,909	$ 3,235	$ 3,114	(195,610)	(27,117)	42,549
(Loss) earnings per limited partner unit:
Goodwill impairment	248,900				54,200				248,851	54,199	0
Long-lived asset impairment	$ 1,600	$ 7,700			$ 5,500				9,305	5,505	0
Common units
Limited Partners' Capital Account [Line Items]
Net (loss) income attributable to limited partners									$ (125,437)	$ (16,324)	$ 23,227
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (3.28)	$ 0.32	$ 0.05	$ 0.00	$ (0.65)	$ 0.08	$ 0.05	$ 0.08	$ (3.20)	$ (0.49)	$ 0.86
Diluted (in dollars per share)	(3.28)	0.32	0.05	0.00	(0.65)	0.08	0.05	0.08	$ (3.20)	$ (0.49)	$ 0.86
Subordinated units
Limited Partners' Capital Account [Line Items]
Net (loss) income attributable to limited partners									$ (70,173)	$ (10,793)	$ 19,322
(Loss) earnings per limited partner unit:
Basic (in dollars per share)	$ (3.28)	$ 0.32	$ (0.03)	$ 0.00	$ (0.65)	$ 0.08	$ 0.05	$ 0.02	$ (2.88)	$ (0.44)	$ 0.79
Diluted (in dollars per share)									$ (2.88)	$ (0.44)	$ 0.79
Previously Reported
Limited Partners' Capital Account [Line Items]
Revenues		$ 103,249	$ 77,274	$ 68,579		$ 79,030	$ 80,796	$ 76,202
Bison Midstream | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues		3,308	3,670	4,056		5,260	4,665	4,399
Polar and Divide Drop Down | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues		0	0	8,582		5,754	5,188	3,179
Drop Down Assets 2016 Acquisition | Adjustment
Limited Partners' Capital Account [Line Items]
Revenues		$ 8,644	$ 5,911	$ 4,870		$ 4,108	$ 2,414	$ 1,922