Edgar Filing: Summit Midstream Partners, LP

10-Q

Table of Contents

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

Form 10-Q

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-35666

Summit Midstream Partners, LP
(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation or organization)		45-5200503 (I.R.S. Employer Identification No.)

1790 Hughes Landing Blvd, Suite 500 The Woodlands, TX (Address of principal executive offices)		77380 (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes o No

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



Large accelerated filer x			Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)			Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		As of April 30, 2016
Common Units		66,587,235 units
General Partner Units		1,354,700 units

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PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015	1
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015	2
	Unaudited Condensed Consolidated Statements of Partners' Capital for the three months ended March 31, 2016 and 2015	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015	5
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	48
Item 4.	Controls and Procedures.	49

PART II	OTHER INFORMATION	50
Item 1.	Legal Proceedings.	50
Item 1A.	Risk Factors.	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	51
Item 6.	Exhibits.	52

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Glossary of Terms

adjusted EBITDA: 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

AMI: area of mutual interest; AMIs require that any production from wells drilled by our customers within the AMI be shipped on our gathering systems and/or processed by our processing facilities

associated natural gas: a form of natural gas which is found with deposits of petroleum, either dissolved in the oil or as a free gas cap above the oil in the reservoir

Bbl: one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons

Bcf: one billion cubic feet

condensate: a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions

conventional resource basin: a basin where natural gas or crude oil production is developed from a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the crude oil and natural gas to readily flow to the wellbore; also referred to as a conventional resource play

delivery point: the point where hydrocarbons or produced water are delivered into a gathering system, processing or fractionation facility or downstream transportation pipeline

distributable cash flow: adjusted EBITDA plus cash interest received and cash taxes received, less cash interest paid, senior notes interest adjustment, cash taxes paid and maintenance capital expenditures

dry gas: natural gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing or treating

EBITDA: net income or loss, plus interest expense, deferred purchase price obligation expense, income tax expense and depreciation and amortization, less interest income and income tax benefit

end users: the ultimate users and consumers of transported energy products

hub: geographic location of a storage facility and multiple pipeline interconnections

LACT unit: lease automatic custody transfer unit; a system for ownership transfer of hydrocarbons or produced water from the production site to trucks, pipelines or storage tanks

Mbbl: one thousand barrels

Mbbl/d: one thousand barrels per day

Mcf: one thousand cubic feet

Mcfe: the equivalent of one thousand cubic feet; generally calculated when liquids are converted into gas; determined using a ratio of six Mcf of natural gas to one barrel of crude oil

MMBtu: one million British Thermal Units

MMcf: one million cubic feet

MMcf/d: one million cubic feet per day

MQD: minimum quarterly distribution; SMLP's partnership agreement has established a minimum quarterly distribution of $0.40 per unit per quarter, or $1.60 per unit per year

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MVC: minimum volume commitment; an MVC contractually obligates a customer to ship natural gas, crude oil and/or produced water and/or use processing services for a minimum quantity of volume throughput

NGLs: natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that, when removed from unprocessed natural gas streams, become liquid under various levels of higher pressure and lower temperature

play: a proven geological formation that contains commercial amounts of hydrocarbons

produced water: water from underground geologic formations that is brought to the surface during the crude oil production process

receipt point: the point where hydrocarbons or produced water are received by or into a gathering system or transportation pipeline

residue gas: the natural gas remaining after being processed and/or treated

segment adjusted EBITDA: calculated 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.

shortfall payment: the payment received from a counterparty when its volume throughput does not meet or exceed its MVC for the applicable period

tailgate: refers to the point at which processed residue natural gas and NGLs leave a processing facility for end-use markets

Tcf: one trillion cubic feet

throughput volume: the volume of natural gas, crude oil or produced water transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput

unconventional resource basin: a basin where natural gas or crude oil production is developed from unconventional sources that require hydraulic fracturing as part of the completion process, for instance, natural gas produced from shale formations and coalbeds; also referred to as an unconventional resource play

wellhead: the equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground

iii

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31,		December 31,
	2016		2015
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	13,087	$	21,793
Accounts receivable	49,550		89,581
Other current assets	2,887		3,573
Total current assets	65,524		114,947
Property, plant and equipment, net	1,833,765		1,812,783
Intangible assets, net	452,667		461,310
Goodwill	16,211		16,211
Investment in equity method investees	757,869		751,168
Other noncurrent assets	8,847		8,253
Total assets	$	3,134,883	$	3,164,672

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	18,783	$	40,808
Due to affiliate	395		1,149
Deferred revenue	677		677
Ad valorem taxes payable	4,288		10,271
Accrued interest	7,733		17,483
Accrued environmental remediation	6,687		7,900
Other current liabilities	12,523		13,297
Total current liabilities	51,086		91,585
Long-term debt	1,312,158		1,267,270
Deferred purchase price obligation	514,890		—
Deferred revenue	46,959		45,486
Noncurrent accrued environmental remediation	5,764		5,764
Other noncurrent liabilities	7,440		7,268
Total liabilities	1,938,297		1,417,373
Commitments and contingencies (Note 15)

Common limited partner capital (66,587 units issued and outstanding at March 31, 2016 and 42,063 units issued and outstanding at December 31, 2015)	1,155,650		744,977
Subordinated limited partner capital (0 units issued and outstanding at March 31, 2016 and 24,410 units issued and outstanding at December 31, 2015)	—		213,631
General partner interests (1,355 units issued and outstanding at March 31, 2016 and December 31, 2015)	29,631		25,634
Noncontrolling interest	11,305		—
Summit Investments' equity in contributed subsidiaries	—		763,057
Total partners' capital	1,196,586		1,747,299
Total liabilities and partners' capital	$	3,134,883	$	3,164,672

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three months ended March 31,
	2016			2015

	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	78,100		$	68,440
Natural gas, NGLs and condensate sales	7,588			12,613
Other revenues	4,883			5,034
Total revenues	90,571			86,087
Costs and expenses:
Cost of natural gas and NGLs	6,290			9,441
Operation and maintenance	25,842			22,791
General and administrative	12,879			11,599
Transaction costs	1,174			110
Depreciation and amortization	27,728			25,530
Gain on asset sales	(63		)	—
Total costs and expenses	73,850			69,471
Other income	22			1
Interest expense	(15,882		)	(14,904		)
Deferred purchase price obligation expense	(7,463		)	—
(Loss) income before income taxes	(6,602		)	1,713
Income tax benefit (expense)	77			(430		)
Income (loss) from equity method investees	2,860			(3,768		)
Net loss	$	(3,665	)	$	(2,485	)
Less:
Net income (loss) attributable to Summit Investments	2,745			(4,152		)
Net income attributable to noncontrolling interest	44			—
Net (loss) income attributable to SMLP	(6,454		)	1,667
Less net (loss) income attributable to general partner, including IDRs	1,810			1,568
Net (loss) income attributable to limited partners	$	(8,264	)	$	99

(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.12	)	$	0.00
Common unit – diluted	$	(0.12	)	$	0.00
Subordinated unit – basic and diluted				$	0.00

Weighted-average limited partner units outstanding:
Common units – basic	66,493			34,439
Common units – diluted	66,493			34,585
Subordinated units – basic and diluted				24,410

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL



	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated			General partner						Total
	(In thousands)
Partners' capital, January 1, 2015	$	649,060		$	293,153		$	24,676		$	863,792		$	1,830,681
Net income (loss)	58			41			1,568			(4,152		)	(2,485		)
Distributions to unitholders	(19,279		)	(13,670		)	(2,144		)	—			(35,093		)
Unit-based compensation	1,312			—			—			—			1,312
Tax withholdings on vested SMLP LTIP awards	(910		)	—			—			—			(910		)
Cash advance to Summit Investments from contributed subsidiaries, net	—			—			—			(14,468		)	(14,468		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			8,408			8,408
Capitalized interest allocated to contributed subsidiaries from Summit Investments	—			—			—			156			156
Capital expenditures paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			—			—
Class B membership interest noncash compensation	—			—			—			251			251
Partners' capital, March 31, 2015	$	630,241		$	279,524		$	24,100		$	853,987		$	1,787,852

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)



	Partners' capital									Noncontrolling interest		Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated			General partner								Total
	(In thousands)
Partners' capital, January 1, 2016	$	744,977		$	213,631		$	25,634		$	—	$	763,057		$	1,747,299
Net (loss) income	(9,304		)	1,040			1,810			44		2,745			(3,665		)
Distributions to unitholders	(24,186		)	(14,034		)	(2,755		)	—		—			(40,975		)
Unit-based compensation	1,761			—			—			—		—			1,761
Tax withholdings on vested SMLP LTIP awards	(786		)	—			—			—		—			(786		)
Subordinated units conversion	200,637			(200,637		)	—			—		—			—
Purchase of 2016 Drop Down Assets	—			—			—			—		(867,427		)	(867,427		)
Establishment of noncontrolling interest	—			—			—			11,261		(11,261		)	—
Distribution of debt related to Carve-Out Financial Statements of Summit Investments	—			—			—			—		342,926			342,926
Excess of consideration paid and recognized over acquired carrying value of 2016 Drop Down Assets	242,486			—			4,942			—		(247,428		)	—
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			—		12,214			12,214
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			—		4,821			4,821
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			—		223			223
Class B membership interest noncash compensation	65			—			—			—		130			195
Partners' capital, March 31, 2016	$	1,155,650		$	—		$	29,631		$	11,305	$	—		$	1,196,586

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three months ended March 31,
	2016			2015

	(In thousands)
Cash flows from operating activities:
Net loss	$	(3,665	)	$	(2,485	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	27,865			25,781
Amortization of deferred loan costs	905			1,108
Deferred purchase price obligation expense	7,463			—
Unit-based and noncash compensation	1,956			1,563
(Income) loss from equity method investees	(2,860		)	3,768
Distributions from equity method investees	11,804			6,849
Gain on asset sales	(63		)	—
Changes in operating assets and liabilities:
Accounts receivable	40,031			41,780
Trade accounts payable	(817		)	(1,575		)
Due to affiliate	(754		)	1,054
Change in deferred revenue	1,473			3,745
Ad valorem taxes payable	(5,982		)	(5,097		)
Accrued interest	(9,750		)	(11,125		)
Accrued environmental remediation	—			(13,719		)
Other, net	(757		)	(3,984		)
Net cash provided by operating activities	66,849			47,663
Cash flows from investing activities:
Capital expenditures	(61,326		)	(49,470		)
Contributions to equity method investees	(15,645		)	(27,830		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(360,000		)	(2,941		)
Other, net	(377		)	—
Net cash used in investing activities	(437,348		)	(80,241		)

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Three months ended March 31,
	2016			2015

	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(40,975		)	(35,093		)
Borrowings under revolving credit facility	424,300			89,000
Repayments under revolving credit facility	(35,300		)	(26,000		)
Deferred loan costs	(2,413		)	(65		)
Cash advance from (to) Summit Investments to (from) contributed subsidiaries, net	12,214			(14,468		)
Expenses paid by Summit Investments on behalf of contributed subsidiaries	4,821			8,408
Other, net	(854		)	(1,056		)
Net cash provided by financing activities	361,793			20,726
Net change in cash and cash equivalents	(8,706		)	(11,852		)
Cash and cash equivalents, beginning of period	21,793			27,811
Cash and cash equivalents, end of period	$	13,087		$	15,959

Supplemental cash flow disclosures:
Cash interest paid	$	25,164		$	25,464
Less capitalized interest	716			527
Interest paid (net of capitalized interest)	$	24,448		$	24,937

Cash paid for taxes	$	—		$	—

Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	13,769		$	45,292
Issuance of deferred purchase price obligation to affiliate to partially fund the 2016 Drop Down	507,427			—
Capitalized interest allocated to contributed subsidiaries from Summit Investments	223			156
Excess of consideration paid and recognized over acquired carrying value of 2016 Drop Down Assets	247,428			—
Distribution of debt related to Carve-Out Financial Statements of Summit Investments (see Notes 2 and 9)	342,926			—

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED 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 our subsidiary, Summit Midstream Holdings, LLC ("Summit Holdings"), a Delaware limited liability company, and its subsidiaries. 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" or our "Sponsor").

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 units. As of March 31, 2016, Summit Investments beneficially owned 29,854,581 SMLP common units.

Our operations are conducted through, and our operating assets are owned by, various wholly owned operating subsidiaries. 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.

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 (i) 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 indirect wholly owned subsidiary of SMP Holdings and (ii) SMP Holdings’ 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively with the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down closed on March 3, 2016 (the "Initial Close"). Upon Initial Close, the Partnership held a 99.0% ownership interest in the 2016 Drop Down Assets and Summit Investments held a 1.0% noncontrolling interest.

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, LLC ("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 Midstream, LLC ("Polar Midstream" or "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 Gathering, LLC ("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;

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•	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 and Codell shale formations in northeastern Colorado;


•	DFW Midstream Services LLC ("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 is 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 formations in southeastern Ohio.

Presentation and Consolidation. We prepare our unaudited condensed 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 unaudited condensed 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. The financial position, results of operations and cash flows of acquired drop down assets, liabilities, expenses or entities that were carved out of entities held by Summit Investments and included herein have been derived from the accounting records of the respective Summit Investments' subsidiary on a carve-out basis (see Note 2).

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the Securities and Exchange Commission (the "SEC"). Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments, including normal recurring accruals, which are necessary to fairly present the unaudited condensed consolidated balance sheet as of March 31, 2016, the unaudited condensed consolidated statements of operations, partners' capital and cash flows for the three-month periods ended March 31, 2016 and 2015. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our annual report on Form 10-K for the year ended December 31, 2015, as filed with the SEC on February 29, 2016 (the "2015 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.

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. 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, we reclassified $9.2 million of deferred loan costs from other noncurrent assets to long-term debt at December 31, 2015 (see Note 2).

In 2015, we made certain reclassifications to conform to current presentation. We 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

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of these reclassifications, which had no impact on net (loss) income, total partners' capital or segment adjusted EBITDA, follows.



	Three months ended March 31, 2015
	(In thousands)
Gathering services and related fees	$	3,419
Other revenues	638
Net impact on total revenues	$	4,057

Cost of natural gas and NGLs	$	4,057
Net impact on cost of natural gas and NGLs and total costs and expenses	$	4,057

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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



	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.

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 net income or loss 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

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loan costs over the life of the respective debt instrument. We recognize amortization of deferred loan costs in interest expense.

Deferred Purchase Price Obligation Income or Expense. We recognized a liability for the deferred purchase price obligation to reflect the expected value of the remaining consideration to be paid in 2020 for the acquisition of the 2016 Drop Down Assets. The calculation of the remaining consideration incorporates estimates of projected capital expenditures and Business Adjusted EBITDA. For balance sheet recognition purposes, we discount the remaining consideration using a commensurate risk-adjusted discount rate and recognize the change in present value in earnings in the period of change. The income or expense represents the change in present value, which comprises a time value of money concept as well as adjustments to projections and the expected value of the remaining consideration (see Note 16).

Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. We record receivables for gain contingencies when they are realized.

Noncontrolling Interest. Noncontrolling interest represents the ownership interests of third-party entities in the net assets of our consolidated subsidiaries, including Summit Investments' ownership interest in the 2016 Drop Down Assets. For financial reporting purposes, we consolidate the 2016 Drop Down Assets with our wholly owned subsidiaries and Summit Investments' interest is shown as noncontrolling interest in partners' capital. We reflect changes in our ownership of the 2016 Drop Down Assets as adjustments to noncontrolling interest.

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) the 1% noncontrolling interest in the 2016 Drop Down Assets (for periods subsequent to the 2016 Drop Down), (ii) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (iii) the general partner's 2% interest in net income or loss, and (iv) any payment of IDRs, by the weighted-average number of limited partner units outstanding. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.

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

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

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Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with parent company debt 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 over consideration paid and recognized.

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

Recently Adopted Accounting Pronouncements. 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. 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 permits an entity to defer and present debt issuance costs as an asset and subsequently amortize 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. The January 2016 adoption of this update resulted in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes (see Note 9). Debt issuance costs associated with the Partnership's revolving credit facility will remain in other noncurrent assets. This standard had no impact on interest expense, net income or loss, EPU or partners' capital.

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


•	ASU No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). There has been no to our position regarding ASU 2014-09 during the first quarter of 2016. See Note 2 to the consolidated financial statements included in the 2015 Annual Report for additional information.

•

ASU No. 2016-02 Leases (Topic 842) ("ASU 2016-02"). ASU 2016-02 requires that lessees recognize all leases on the balance sheet, with the exception of short-term leases. A lease liability will be recorded for the obligation of a lessee to make lease payments arising from a lease. A right-of-use asset, will be recorded which represents the lessee’s right to use, or to control the use of, a specified asset for a lease term. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 is effective for public companies for fiscal years beginning after December 15, 2019, and requires the modified retrospective approach for transition.


•	ASU No. 2016-08 Revenue From Contracts With Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) ("ASU No. 2016-08"). ASU No. 2016-08 does not change the core principle of Topic 606, rather it clarifies the implementation guidance on principal versus agent considerations. The effective date and transition for this update are the same as ASU 2014-09.

•

ASU No. 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting ("ASU 2016-09"). ASU 2016-09 simplifies several aspects for share-based payment award transactions, including income tax consequences, the liability or equity classification of awards and classification on the statement of cash flows. ASU 2016-09 is effective for public companies for fiscal years beginning after December 15, 2016. It does not specify a single transition approach, rather it specifies retrospective, modified retrospective and/or prospective transition approaches based on the aspect being applied.

•

ASU No. 2016-10 Revenue From Contracts With Customers (Topic 606): Identifying Performance Obligations and Licensing ("ASU No. 2016-10"). ASU No. 2016-10 clarifies the following two aspects of Topic 606 (i) identifying performance obligations and (ii) the licensing implementation guidance, while retaining the related principles for those areas. The effective date and transition for this update are the same as ASU 2014-09.

Recent accounting guidance not discussed above is not applicable, did not have, or is not expected to have a material impact on our financial statements. For additional information on new accounting pronouncements and recent accounting guidance and their impact, if any, on our financial position or results of operations, see Note 2 of the notes to the consolidated financial statements included in the 2015 Annual Report.

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3. SEGMENT INFORMATION

As of March 31, 2016, 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.

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.

Assets by reportable segment follow.



	March 31, 2016		December 31, 2015
	(In thousands)
Assets:
Utica Shale (1)	$	922,717	$	886,223
Williston Basin	725,641		740,361
Piceance/DJ Basins	829,608		866,095
Barnett Shale	411,118		416,586
Marcellus Shale	232,017		233,116
Total reportable segment assets	3,121,101		3,142,381
Corporate	13,782		22,291
Total assets	$	3,134,883	$	3,164,672

__________

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

Revenues by reportable segment follow.



	Three months ended March 31,
	2016		2015
	(In thousands)
Revenues:
Utica Shale	$	4,283	$	389
Williston Basin	30,008		23,066
Piceance/DJ Basins	28,993		30,894
Barnett Shale	20,402		23,897
Marcellus Shale	6,885		7,841
Total reportable segment revenues and total revenues	$	90,571	$	86,087

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



	Three months ended March 31,
	2016	2015
Percentage of total revenues:
Counterparty A - Piceance/DJ Basins	*	13	%

__________

* 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.



	Three months ended March 31,
	2016		2015
	(In thousands)
Depreciation and amortization:
Utica Shale	$	844	$	139
Williston Basin	8,357		7,368
Piceance/DJ Basins	12,273		11,783
Barnett Shale	4,056		4,157
Marcellus Shale	2,219		2,168
Total reportable segment depreciation and amortization	27,749		25,615
Corporate	116		166
Total depreciation and amortization	$	27,865	$	25,781

Capital expenditures by reportable segment follow.



	Three months ended March 31,
	2016		2015
	(In thousands)
Capital expenditures:
Utica Shale	$	34,988	$	22,565
Williston Basin	18,034		18,310
Piceance/DJ Basins	5,824		6,808
Barnett Shale	563		893
Marcellus Shale	1,738		496
Total reportable segment capital expenditures	61,147		49,072
Corporate	179		398
Total capital expenditures	$	61,326	$	49,470

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.

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Segment adjusted EBITDA by reportable segment follows.



	Three months ended March 31,
	2016		2015
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	15,577	$	5,206
Williston Basin	19,719		10,975
Piceance/DJ Basins	24,817		28,702
Barnett Shale	14,077		16,760
Marcellus Shale	4,600		6,536
Total reportable segment adjusted EBITDA	$	78,790	$	68,179

__________

(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 before income taxes to total reportable segment adjusted EBITDA follows.



	Three months ended March 31,
	2016			2015
	(In thousands)
Reconciliation of Loss Before Income Taxes to Segment Adjusted EBITDA:
Loss before income taxes	$	(6,602	)	$	1,713
Add:
Allocated corporate expenses	8,781			6,623
Interest expense	15,882			14,904
Deferred purchase price obligation expense	7,463			—
Depreciation and amortization	27,865			25,781
Proportional adjusted EBITDA for equity method investees	12,388			5,263
Adjustments related to MVC shortfall payments	11,142			12,333
Unit-based and noncash compensation	1,956			1,563
Loss on asset sales	—			—
Less:
Interest income	22			1
Gain on asset sales	63			—
Total reportable segment adjusted EBITDA	$	78,790		$	68,179

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, deferred purchase price obligation income or 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 unaudited condensed consolidated financial statements.

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Adjustments related to MVC shortfall payments by reportable segment follow.



	Three months ended March 31,
	2016		2015
	(In thousands)
Adjustments related to MVC shortfall payments:
Williston Basin	$	3,536	$	2,653
Piceance/DJ Basins	7,517		9,903
Barnett Shale	89		(223		)
Total adjustments related to MVC shortfall payments	$	11,142	$	12,333

4. PROPERTY, PLANT, AND EQUIPMENT, NET

Details on property, plant, and equipment follow.



	March 31, 2016		December 31, 2015
	(In thousands)
Gathering and processing systems and related equipment	$	1,918,080	$	1,883,139
Construction in progress	77,596		75,132
Land and line fill	11,436		11,055
Other	32,931		32,427
Total	2,040,043		2,001,753
Less accumulated depreciation	206,278		188,970
Property, plant, and equipment, net	$	1,833,765	$	1,812,783

Depreciation expense and capitalized interest follow.



	Three months ended March 31,
	2016		2015
	(In thousands)
Depreciation expense	$	17,370	$	15,264
Capitalized interest	716		527

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.



	March 31, 2016
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net

		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(9,872	)	$	14,323
Contract intangibles	12.5	426,464		(119,906		)	306,558
Rights-of-way	26.1	152,195		(20,409		)	131,786
Total intangible assets		$	602,854	$	(150,187	)	$	452,667

Unfavorable gas gathering contract	10.0	$	10,962	$	(6,278	)	$	4,684

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	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

We recognized amortization expense in other revenues as follows:



	Three months ended March 31,
	2016			2015

	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(338	)	$	(426	)
Amortization expense – unfavorable gas gathering contract	201			175

We recognized amortization expense in costs and expenses as follows:



	Three months ended March 31,
	2016		2015

	(In thousands)
Amortization expense – contract intangibles	$	8,854	$	8,835
Amortization expense – rights-of-way	1,503		1,431

The estimated aggregate annual amortization expected to be recognized for the remainder of 2016 and each of the four succeeding fiscal years follows.



	Intangible assets		Unfavorable gas gathering contract

	(In thousands)
2016	$	32,500	$	729
2017	42,028		1,047
2018	41,482		1,035
2019	41,727		1,045
2020	44,373		828

6. 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 amount. There have been no impairments of goodwill during the three months ended March 31, 2016.

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

Fair Value Measurement. Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments, as discussed in the 2015 Annual Report. Differing assumptions regarding any of these inputs could have a significant effect on

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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) $5.1 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 will result in a net decrease to its 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, at which point SMLP began making contributions and receiving distributions such that it maintained its 40.0% ownership interest through March 31, 2016.

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A rollforward of the investment in equity method investees follows.



	2016			2015
	(In thousands)
Investment in equity method investees, January 1	$	751,168		$	706,172
Cash contributions	15,645			27,830
Cash distributions	(11,804		)	(6,849		)
Income (loss) from equity method investees	6,198			(430		)
Amortization of basis difference in equity method investees	(3,338		)	(3,338		)
Investment in equity method investees, March 31	757,869			723,385
March cash contributions	(4,291		)	—
March cash distributions	4,816			1,884
Basis difference	(153,551		)	(166,903		)
Investment in equity method investees, net of basis difference, February 29, 2016 and February 28, 2015	$	604,843		$	558,366

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



	February 29, 2016		February 28, 2015
	(In thousands)
Total assets	$	1,513,668	$	1,427,142
Total liabilities	45,176		74,674
Members' equity	1,468,492		1,352,468

The following table presents summarized statements of operations information for Ohio Gathering for the three-month periods ended February 29, 2016 and February 28, 2015.



	Three months ended February 29, 2016		Three months ended February 28, 2015
	(In thousands)
Total revenues	$	42,997	$	23,680
Total operating expenses	27,092		24,757
Net income (loss)	15,725		(1,077		)

8. DEFERRED REVENUE

A rollforward of current deferred revenue follows.



	Williston Basin		Barnett Shale		Piceance/DJ Basins			Total current
	(In thousands)
Current deferred revenue, January 1, 2016	$	—	$	677	$	—		$	677
Additions	—		—		2,722			2,722
Less revenue recognized	—		—		(2,722		)	(2,722		)
Current deferred revenue, March 31, 2016	$	—	$	677	$	—		$	677

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A rollforward of noncurrent deferred revenue follows.



	Williston Basin		Barnett Shale		Piceance/DJ Basins		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2016	$	29,002	$	—	$	16,484	$	45,486
Additions	235		—		1,238		1,473
Less revenue recognized	—		—		—		—
Noncurrent deferred revenue, March 31, 2016	$	29,237	$	—	$	17,722	$	46,959

As of March 31, 2016, accounts receivable included $1.6 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:



	March 31, 2016			December 31, 2015
	(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (3.19% at March 31, 2016 and 2.93% at December 31, 2015) due November 2018	$	721,000		$	344,000
SMP Holdings variable rate senior secured revolving credit facility (2.43% at December 31, 2015) (1)	—			115,000
SMP Holdings variable rate senior secured term loan (2.43% at December 31, 2015) (1)	—			217,500
Summit Holdings 5.50% Senior unsecured notes due August 2022	300,000			300,000
less unamortized deferred loan costs (2)	(3,981		)	(4,139		)
Summit Holdings 7.50% Senior unsecured notes due July 2021	300,000			300,000
less unamortized deferred loan costs (2)	(4,861		)	(5,091		)
Total long-term debt	$	1,312,158		$	1,267,270

__________

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

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

Revolving Credit Facility. We have a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans (the "revolving credit facility"). On February 25, 2016, we closed on an amendment to the revolving credit facility, which became effective concurrent with the Initial Close 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. The revolving credit facility matures in November 2018 and includes a $200.0 million accordion feature. It is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The revolving credit facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries.

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 March 31, 2016, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 3.19% and the unused portion of the revolving credit facility totaled $529.0 million (subject to a commitment fee of 0.50%).

The revolving credit agreement 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

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power purchase agreements; (v) enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period; and (vi) prohibits the payment of distributions by Summit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings can make. In addition, the revolving credit facility requires Summit Holdings to maintain a ratio of consolidated trailing 12-month earnings before interest, income taxes, depreciation and amortization ("EBITDA," as defined in the credit agreement) to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions. Additionally, the total leverage ratio upper limit can be increased from 5.0 to 1.0 to 5.5 to 1.0 at our option, subject to the inclusion of a senior secured leverage ratio (senior secured net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) upper limit of 3.75 to 1.0.

As of March 31, 2016, we were in compliance with the revolving credit facility's covenants. There were no defaults or events of default during the three months ended March 31, 2016.

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").

SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the 5.5% senior notes and the 7.5% 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, the 5.5% senior notes and the 7.5% senior notes. Finance Corp. has no independent assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the 5.5% senior notes and the 7.5% 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.

As of March 31, 2016, we were in compliance with the covenants of the 5.5% senior notes and the 7.5% senior notes. There were no defaults or events of default during the three months ended March 31, 2016.

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 ("NGLs") 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 49% of total accounts receivable at March 31, 2016, compared with 68% as of December 31, 2015.

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

The deferred purchase price obligation's carrying value is its fair value because carrying value represents the present value of the payment expected to be made in 2020 (see Note 16 for additional information). Our calculation of the present value of the expected cash payment for the 2016 Drop Down Assets involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a material effect on the cash payment and its present value. As such, its fair value measurement is classified as a non-recurring Level 3 measurement in the fair value hierarchy because our assumptions and judgments are not observable from objective sources (see Note 16).

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The roll-forward of the Level 3 liabilities measured at fair value on a recurring basis follows.



	Three months ended March 31, 2016		Three months ended March 31, 2015
	(In thousands)
Level 3 liabilities, beginning of period	$	—	$	—
Additions	507,427		—
Change in fair value	7,463		—
Level 3 liabilities, end of period	$	514,890	$	—

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



	March 31, 2016				December 31, 2015
	Carrying value		Estimated fair value (1)		Carrying value		Estimated fair value (1)
	(In thousands)
Summit Holdings revolving credit facility	$	721,000	$	721,000	$	344,000	$	344,000
SMP Holdings revolving credit facility (2)	—		—		115,000		115,000
SMP Holdings term loan (2)	—		—		217,500		217,500
5.5% Senior notes ($300.0 million principal)	296,019		213,000		295,861		224,000
7.5% Senior notes ($300.0 million principal)	295,139		237,750		294,909		257,000

__________

(1) All estimated fair value calculations are Level 2.

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

The outstanding balance on the revolving credit facility 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 March 31, 2016 and December 31, 2015. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

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, 2016	42,062,644	24,409,850		1,354,700	67,827,194
Net units issued under SMLP LTIP	114,741	—		—	114,741
Subordinated unit conversion	24,409,850	(24,409,850	)	—	—
Units, March 31, 2016	66,587,235	—		1,354,700	67,941,935

Subordination. Prior to the end of the subordination period, the principal difference between our common units and subordinated units was that holders of the subordinated units were not entitled to receive any distribution of available cash until the common units had received the minimum quarterly distribution ("MQD") plus any arrearages in the payment of the MQD from prior quarters. 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.

Noncontrolling Interest. We have recorded Summit Investments' retained ownership interest in the 2016 Drop Down Assets as a noncontrolling interest in the consolidated financial statements.

Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of the 2016 Drop Down Assets and Polar and Divide that have

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been acquired by SMLP. The balance also reflects net income or loss attributable to Summit Investments for the 2016 Drop Down Assets and Polar and Divide for the periods beginning on the dates they were acquired or formed by Summit Investments and ending on the dates they were acquired by the Partnership. During the three months ended March 31, 2016 and 2015, net income or loss was attributed to Summit Investments for:


•	the 2016 Drop Down Assets for the period from January 1, 2015 to March 3, 2016 and


•	Polar and Divide for the period from January 1, 2015 to May 18, 2015.

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

2016 Drop Down. On March 3, 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We paid cash consideration of $360.0 million and recognized a deferred purchase price obligation of $507.4 million in exchange for Summit Investments' $1.11 billion net investment in the 2016 Drop Down Assets (see Note 15). We recognized a capital contribution from Summit Investments for the difference between (i) the cash consideration paid and the deferred purchase price obligation and (ii) Summit Investments' net investment in the 2016 Drop Down Assets.

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



Summit Investments' net investment in the 2016 Drop Down Assets	$	771,929
SMP Holdings borrowings allocated to 2016 Drop Down Assets and retained by Summit Investments	342,926
Acquired carrying value of 2016 Drop Down Assets			$	1,114,855

Deferred purchase price obligation	$	507,427
Borrowings under revolving credit facility	360,000
Total consideration paid and recognized by SMLP			867,427
Excess of acquired carrying value over consideration paid and recognized			$	247,428

Allocation of capital contribution:
General partner interest	$	4,942
Common limited partner interest	242,486
Partners' capital contribution – excess of acquired carrying value over consideration paid and recognized			$	247,428

Cash Distributions Paid and Declared. We paid the following per-unit distributions during the three months ended March 31:



	Three months ended March 31,
	2016		2015
Per-unit distributions to unitholders	$	0.575	$	0.560

On April 21, 2016, the board of directors of our general partner declared a distribution of $0.575 per unit for the quarterly period ended March 31, 2016. This distribution, which totaled $41.0 million, will be paid on May 13, 2016 to unitholders of record at the close of business on May 6, 2016. We allocated the May 2016 distribution using a 25% marginal percentage interest in accordance with the third target distribution level.

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%, of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the three months ended March 31 follow.



	Three months ended March 31,
	2016		2015
	(In thousands)
IDR payments	$	1,935	$	1,442

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For the purposes of calculating net income or loss 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.



	Three months ended March 31,
	2016			2015
	(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	$	(8,264	)	$	69
Net income attributable to subordinated units (1)				30
Net (loss) income attributable to limited partners	$	(8,264	)	$	99

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	66,493			34,439
Effect of nonvested phantom units	—			146
Weighted-average common units outstanding – diluted	66,493			34,585

Weighted-average subordinated units outstanding – basic and diluted (1)				24,410

(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.12	)	$	0.00
Common unit – diluted	$	(0.12	)	$	0.00
Subordinated unit – basic and diluted (1)				$	0.00

__________

(1) The subordinated units converted to common units on a one-for-one basis in February 2016 (see Note 11).

During the three months ended March 31, 2016 and 2015, we excluded 496,959 and 8,524 nonvested phantom units, respectively, in our calculation of diluted EPU because they were anti-dilutive.

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. Items to note:


•	In March 2016, we granted 488,482 phantom units to employees in connection with our annual incentive compensation award cycle. These awards had a grant date fair value of $14.82 and vest ratably over a three-year period.


•	Also in March 2016, 120,920 phantom units vested.


•	As of March 31, 2016, approximately 3.9 million common units remained available for future issuance.

SMP Net Profits Interests. In connection with the formation of Summit Investments, up to 7.5% of total membership interests were authorized for issuance (the "SMP Net Profits Interests"). These membership interests were not contributed to SMLP in connection with its IPO. The expense associated with the SMP Net Profits Interests was allocated to Summit Investments' subsidiaries other than SMLP and its subsidiaries after the IPO. In connection with our acquisitions of the 2016 Drop Down Assets and Polar and Divide, we recognized the SMP Net

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Profits Interests' noncash compensation expense that had been allocated to the contributed subsidiaries prior to their respective drop down date due to common control.

Noncash compensation recognized in general and administrative expense related to the SMP Net Profits Interests was as follows:



	Three months ended March 31,
	2016		2015
	(In thousands)
SMP Net Profits Interests noncash compensation	$	195	$	251

14. RELATED-PARTY TRANSACTIONS

Acquisitions. See Notes 1, 9, 11 and 16 for disclosure of the 2016 Drop Down and its funding.

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:



	Three months ended March 31,
	2016		2015
	(In thousands)
Operation and maintenance expense	$	6,749	$	6,474
General and administrative expense	7,778		7,135

Expenses Incurred by Summit Investments. Prior to the 2016 Drop Down and the Polar and Divide 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


•	noncash compensation expense for the SMP Net Profits Interests, which were accounted for as compensatory awards. As such, the annual expense associated with the SMP Net Profits was allocated to the respective contributed subsidiary.

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

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:



	Three months ended March 31,
	2016		2015
	(In thousands)
Rent expense	$	616	$	506

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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, 2015	$	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
Payments made by affiliates	(1,213		)
Accrued environmental remediation, March 31, 2016	$	12,451

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

In 2015, the U.S. Department of Justice 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.

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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;


•	plus all Business Adjusted EBITDA from the 2016 Drop Down Assets between Initial Close and December 31, 2019, less the 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 the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets) was $860.3 million, which had a net present value of $507.4 million, using a discount rate of 13%. As of March 31, 2016, the net present value of this obligation was $514.9 million and has been recorded on the consolidated balance sheet. Deferred purchase price obligation expense for the three months ended March 31, 2016 was $7.5 million. Any subsequent changes to the estimated future payment obligation will be calculated using a discounted cash flow model with a commensurate risk-adjusted discount rate. Such changes and the impact on the liability due to the passage of time will be recorded as deferred purchase price obligation income or expense on the consolidated statements of operations in the period of the change.

At the discretion of the board of directors of our general partner, the Deferred Purchase Price Obligation can be paid in cash, SMLP common units or a combination thereof. We currently expect that the Deferred Purchase Price Obligation will be financed with a combination of (i) net proceeds from the sale of common units by us, (ii) the net proceeds from the issuance of senior unsecured debt by us, (iii) borrowings under our revolving credit facility and/or (iv) other internally generated sources of cash.

Because of the common control aspects in a drop down transaction, the 2016 Drop Down was deemed a transaction between entities under common control and, as such, has been accounted for on an “as-if pooled” basis

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for all periods in which common control existed. Subsequent to Initial Close, SMLP’s financial results will 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 and intangible assets acquired and liabilities assumed were recorded based on their fair values as of initial acquisition on February 15, 2013. Both Bison Midstream and Polar Midstream have previously been carved out of Meadowlark Midstream. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the system. We recognized the 2016 acquisition of Meadowlark Midstream at Summit Investments' historical cost of construction and fair value of assets and liabilities at acquisition, which reflected its fair value accounting for the initial acquisition of Meadowlark Midstream in 2013, due to common control.

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



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.

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 Assets and Polar and Divide have been combined to reflect the historical operations, financial position and cash flows from the date common control began. Revenues and net income or loss for the previously separate entities and the combined amounts, as presented in these unaudited condensed consolidated financial statements follow.



	Three months ended March 31,
	2016			2015
	(In thousands)
SMLP revenues	$	81,704		$	72,635
2016 Drop Down Assets revenues	8,867			4,870
Polar and Divide revenues (1)				8,582
Combined revenues	$	90,571		$	86,087

SMLP net (loss) income	$	(6,410	)	$	1,667
2016 Drop Down Assets net income (loss)	2,745			(7,498		)
Polar and Divide net income (1)				3,346
Combined net loss	$	(3,665	)	$	(2,485	)

__________

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

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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 for the period since December 31, 2015. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the 2015 Annual Report. Among other things, those 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 the Forward-Looking Statements section below. 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. 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 G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations 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, a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

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Ohio Gathering operates a natural gas gathering system and a condensate stabilization facility in the Appalachian Basin, which includes the Utica and Point Pleasant formations in southeastern Ohio.

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

The following table presents certain consolidated financial data.



	Three months ended March 31,
	2016			2015
	(In thousands)
Selected Financial Results:
Net loss	$	(3,665	)	$	(2,485	)
EBITDA (1)	47,446			38,629
Adjusted EBITDA (1)	70,009			61,556
Distributable cash flow (1)	51,538			42,758

Acquisitions of gathering systems (2)	$	867,427		$	2,941
Capital expenditures (3)	61,326			49,470
Contributions to equity method investees	15,645			27,830

Borrowings under revolving credit facility, net	389,000			63,000
Distributions to unitholders	40,975			35,093

_________

(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 and recognized, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs. For additional information, see Notes 11 and 16 to the unaudited condensed consolidated financial statements.

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

Three months ended March 31, 2016. In the first quarter of 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We funded the drop down with borrowings under our revolving credit facility and the execution of a deferred purchase price obligation with Summit Investments.

The per-unit distribution declared in respect of the first quarter of 2016 increased 1.8% over the per-unit distribution declared in respect of the first quarter of 2015.

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;

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•	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. For additional information, see the "Trends and Outlook" section of MD&A included in the 2015 Annual Report.

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 and is served by Summit Utica;


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


•	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.

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.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three months ended March 31, 2016, except as noted below.

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;


•	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

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•	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 (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitments 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.

Additional Information. For additional information on how these metrics help us manage our business, see the "How We Evaluate Our Operations" section of MD&A included in the 2015 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.

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Results of Operations

Consolidated Overview of the Three Months Ended March 31, 2016 and 2015

The following table presents certain consolidated and operating data.



	Three months ended March 31,
	2016			2015

	(In thousands)
Revenues:
Gathering services and related fees	$	78,100		$	68,440
Natural gas, NGLs and condensate sales	7,588			12,613
Other revenues	4,883			5,034
Total revenues	90,571			86,087
Costs and expenses:
Cost of natural gas and NGLs	6,290			9,441
Operation and maintenance	25,842			22,791
General and administrative	12,879			11,599
Transaction costs	1,174			110
Depreciation and amortization	27,728			25,530
Gain on asset sales	(63		)	—
Total costs and expenses	73,850			69,471
Other income	22			1
Interest expense	(15,882		)	(14,904		)
Deferred purchase price obligation expense	(7,463		)	—
(Loss) income before income taxes	(6,602		)	1,713
Income tax benefit (expense)	77			(430		)
Income (loss) from equity method investees	2,860			(3,768		)
Net loss	$	(3,665	)	$	(2,485	)

Operating Data:
Aggregate average throughput – gas (MMcf/d)	1,523			1,605
Aggregate average throughput rate per Mcf – gas	$	0.44		$	0.42
Average throughput – liquids (Mbbl/d)	95.0			53.4
Average throughput rate per Bbl – liquids	$	1.95		$	1.74

Volumes – Gas. Aggregate natural gas throughput volumes decreased in 2016 primarily reflecting declines in volume throughput for Mountaineer Midstream, DFW Midstream and Grand River partially offset by an increase in volume throughput on Summit Utica.

Volumes – Liquids. Average daily throughput for crude oil and produced water increased in 2016 primarily reflecting new pad site connections and producers' drilling activity on the Polar and Divide system. The impact of a rupture and early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained first quarter 2015 volume throughput (see Note 15 to the unaudited condensed consolidated financial statements).

Revenues. Total revenues increased $4.5 million in 2016 primarily reflecting:


•	an increase in gathering services and related fees for the Polar and Divide and Summit Utica systems, partially offset by declines on DFW Midstream, Grand River and Mountaineer Midstream.


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

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Gathering Services and Related Fees. The increase in gathering services and related fees during 2016 was primarily driven by higher volume throughput on the Polar and Divide system and the development of the Summit Utica system.

The aggregate average throughput rate for natural gas increased to $0.44/Mcf during 2016, compared with $0.42/Mcf during 2015, largely due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.95/Bbl during 2016, compared with $1.74/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.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for 2016 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.

Costs and Expenses. Total costs and expenses increased $4.4 million, or 6%, in 2016 primarily reflecting:


•	the impact of lower commodity prices on cost of natural gas and NGLs at Bison Midstream and Grand River.


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


•	an increase in operation and maintenance, primarily as a result of repairs to rights-of-way at Mountaineer Midstream.


•	an increase in transaction costs, primarily as a result of the 2016 Drop Down.


•	remediation expenses associated with a produced water rupture at Polar and Divide that was identified in January 2015.

Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs in 2016 was largely driven by declining commodity prices and the associated impact on our percent-of-proceeds arrangements at Bison Midstream and Grand River.

Operation and Maintenance. Operation and maintenance expense increased during 2016 primarily reflecting costs associated with repairs to rights-of-way at Mountaineer Midstream and certain environmental remediation expenses at Polar and Divide.

General and Administrative. General and administrative expense increased during 2016 reflecting an increase in expenses for salaries, benefits and unit-based compensation as well as our recognition of an allowance for gathering receivables from a certain Grand River customer. The impact of these items were partially offset by a decline in expenses for professional services.

Transaction Costs. Transaction costs recognized primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.

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

Interest Expense. The increase in interest expense during 2016 was primarily driven by borrowing costs associated with our revolving credit facility and the Summit Investments' debt that had been allocated to the 2016 Drop Down Assets.

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

Segment Overview of the Three Months Ended March 31, 2016 and 2015

Utica Shale. Our ownership interest in Ohio Gathering is the primary component of the Utica Shale reportable segment. Ohio Gathering, a natural gas gathering system and a condensate stabilization facility, was acquired from a subsidiary of Summit Investments in March 2016. 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.

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Volume throughput for our Utica Shale reportable segment, exclusive of Ohio Gathering, follows.



	Utica Shale (1)
	Three months ended March 31,		Percentage Change
	2016	2015	2016 v. 2015
Operating Data:
Average throughput (MMcf/d)	132	12	*

__________

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

* Not considered meaningful

Volume throughput for the first quarter of 2016 increased due to our continued buildout of the Summit Utica gathering system and our customers’ commissioning of new wells throughout 2015 and into the first quarter of 2016.

Financial data for our Utica Shale reportable segment follows.



	Utica Shale
	Three months ended March 31,				Percentage Change
	2016		2015		2016 v. 2015

	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	4,283	$	389	*
Total revenues	4,283		389		*
Costs and expenses:
Operation and maintenance	525		243		116	%
General and administrative	569		203		*
Depreciation and amortization	844		139		*
Total costs and expenses	1,938		585		*
Add:
Proportional adjusted EBITDA for equity method investees	12,388		5,263
Depreciation and amortization	844		139
Segment adjusted EBITDA	$	15,577	$	5,206	*

__________

* Not considered meaningful

Three months ended March 31, 2016. Segment adjusted EBITDA increased $10.4 million during 2016 reflecting:


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


•	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, which comprises crude oil and produced water gathering systems and transmission pipelines, was acquired from subsidiaries of Summit Investments in May 2015 and March 2016. 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.

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Operating data for our Williston Basin reportable segment follows.



	Williston Basin
	Three months ended March 31,				Percentage Change
	2016		2015		2016 v. 2015
Operating Data:
Average throughput – natural gas (MMcf/d)	25		21		19	%
Average throughput rate per Mcf – gas	$	2.74	$	2.66	3	%
Average throughput (Mbbl/d) – liquids	95.0		53.4		78	%
Average throughput rate per Bbl – liquids	$	1.95	$	1.74	12	%

Natural gas. Natural gas volume throughput increased in 2016 due to the development of the Tioga Midstream system throughout 2015 and into the first quarter of 2016. The increase in natural gas gathering rates in 2016 was primarily a result of a shift in volume mix, partially offset by the impact of declining commodity prices on volumes associated with a percent-of-proceeds contract.

Liquids. The increase in liquids volume throughput in 2016 reflects the completion of new wells across our gathering footprint and the connection of pad sites that had been previously using third-party trucks to gather production. The increase in average throughput rate for liquids for 2016 was primarily due to a shift in customer mix and the impact of a rate redetermination which went into effect in the first quarter of 2016.

Financial data for our Williston Basin reportable segment follows.



	Williston Basin
	Three months ended March 31,				Percentage Change
	2016		2015 (1)		2016 v. 2015

	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	22,415	$	12,851	74	%
Natural gas, NGLs and condensate sales	4,276		7,358		(42	)%
Other revenues	3,317		2,857		16	%
Total revenues	30,008		23,066		30	%
Costs and expenses:
Cost of natural gas and NGLs	4,626		7,136		(35	)%
Operation and maintenance	8,210		5,649		45	%
General and administrative	989		2,044		(52	)%
Depreciation and amortization	8,357		7,368		13	%
Total costs and expenses	22,182		22,197		—	%
Add:
Depreciation and amortization	8,357		7,368
Adjustments related to MVC shortfall payments	3,536		2,653
Unit-based compensation	—		85
Segment adjusted EBITDA	$	19,719	$	10,975	80	%

__________

(1) In the fourth quarter of 2015, we evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts and (ii) certain Bison Midstream pass-through expenses. 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. These reclassifications had no impact on segment adjusted EBITDA.

Three months ended March 31, 2016. Segment adjusted EBITDA increased $8.7 million during 2016 reflecting:


•	the impact of higher volume throughput on gathering services and related fees due to the development of Tioga Midstream.

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•	higher gathering rates associated with a rate redetermination, which went into effect in the first quarter of 2016.


•	a higher allocation of certain corporate general and administrative expenses in the first quarter of 2015 for both Polar and Divide and Tioga Midstream.


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


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

Other revenues and operation and maintenance also reflect the effect of a decrease in certain connection fee pass through, which, due to their nature, have no impact on segment adjusted EBITDA. Depreciation and amortization increased during three months ended March 31, 2016 largely as a result of assets placed into service for the 2016 Drop Down Assets.

Piceance/DJ Basins. Grand River, a natural gas gathering and processing system, provides our midstream services for the Piceance/DJ Basins reportable segment. Niobrara G&P is an associated natural gas gathering and processing system located in the DJ Basin serving producers primarily targeting crude oil production from the Niobrara and Codell shale formations in northern Colorado and southern Wyoming. It was acquired in connection with the 2016 Drop Down in March 2016. Common control began in February 2013 for Niobrara G&P. As such, our results include activity for Niobrara G&P for all periods presented. For additional information, see the notes to the unaudited condensed consolidated financial statements.

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



	Piceance/DJ Basins
	Three months ended March 31,				Percentage Change
	2016		2015		2016 v. 2015
Operating Data:
Average throughput (MMcf/d)	572		622		(8	)%
Average throughput rate per Mcf	$	0.49	$	0.46	7	%

Volume throughput decreased during 2016 primarily as a result of the continued suspension of drilling activities by Grand River's anchor customer. The aggregate average throughput rate increased during 2016 largely as a result of a shift in volume throughput mix.

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



	Piceance/DJ Basins
	Three months ended March 31,					Percentage Change
	2016			2015		2016 v. 2015

	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	25,392		$	25,564	(1	)%
Natural gas, NGLs and condensate sales	2,203			3,334		(34	)%
Other revenues	1,398			1,996		(30	)%
Total revenues	28,993			30,894		(6	)%
Costs and expenses:
Cost of natural gas and NGLs	1,664			2,305		(28	)%
Operation and maintenance	8,597			8,872		(3	)%
General and administrative	1,432			918		56	%
Depreciation and amortization	12,273			11,783		4	%
Gain on asset sales	(63		)	—		*
Total costs and expenses	23,903			23,878		—	%
Add:
Depreciation and amortization	12,273			11,783
Adjustments related to MVC shortfall payments	7,517			9,903
Gain on asset sales	(63		)	—
Segment adjusted EBITDA	$	24,817		$	28,702	(14	)%

__________

* Not considered meaningful

Three months ended March 31, 2016. Segment adjusted EBITDA decreased $3.9 million during 2016 reflecting:


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


•	the impact of declining volumes from Grand River's anchor customer.


•	our recognition of an allowance for gathering receivables from a certain customer.

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 the three months ended March 31, 2016 largely as a result of an increase in contract amortization for Grand River's anchor customer. A portion of the decline in adjustments for MVC shortfall payments is associated with our September 2015 decision to no longer defer MVC shortfall payments from a certain Grand River customer. As a result, gathering revenue increased in the first quarter of 2016, offsetting the decline in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 7 to the consolidated financial statements included in the 2015 Annual Report for additional information).

Barnett Shale. DFW Midstream, a natural gas gathering system, provides our midstream services for the Barnett Shale reportable segment.

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Operating data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Three months ended March 31,				Percentage Change
	2016		2015		2016 v. 2015
Operating Data:
Average throughput (MMcf/d)	341		403		(15	)%
Average throughput rate per Mcf	$	0.60	$	0.60	—	%

Volume throughput declined in 2016 reflecting reduced production due to natural production declines.

Financial data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Three months ended March 31,					Percentage Change
	2016		2015			2016 v. 2015

	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	19,125	$	21,794		(12	)%
Natural gas, NGLs and condensate sales	1,109		1,922			(42	)%
Other revenues	168		181			(7	)%
Total revenues	20,402		23,897			(15	)%
Costs and expenses:
Operation and maintenance	6,314		6,812			(7	)%
General and administrative	237		353			(33	)%
Depreciation and amortization	3,919		3,906			—	%
Total costs and expenses	10,470		11,071			(5	)%
Add:
Depreciation and amortization	4,056		4,157
Adjustments related to MVC shortfall payments	89		(223		)
Segment adjusted EBITDA	$	14,077	$	16,760		(16	)%

Three months ended March 31, 2016. Segment adjusted EBITDA decreased $2.7 million during 2016 reflecting:


•	a reduction in gathering services and related fees largely as a result of reduced volume throughput.


•	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.

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Marcellus Shale. Mountaineer Midstream, a natural gas gathering system, provides our midstream services for the Marcellus Shale reportable segment.

Volume throughput for our Marcellus Shale reportable segment follows.



	Marcellus Shale (1)
	Three months ended March 31,		Percentage Change
	2016	2015	2016 v. 2015
Operating Data:
Average throughput (MMcf/d)	453	547	(17	)%

__________

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

Volume throughput declined in 2016 due to our anchor customer’s decision to defer completion activities in 2015 and not offset natural production declines.

Financial data for our Marcellus Shale reportable segment follows.



	Marcellus Shale
	Three months ended March 31,				Percentage Change
	2016		2015		2016 v. 2015

	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,885	$	7,841	(12	)%
Total revenues	6,885		7,841		(12	)%
Costs and expenses:
Operation and maintenance	2,196		1,215		81	%
General and administrative	89		90		(1	)%
Depreciation and amortization	2,219		2,168		2	%
Total costs and expenses	4,504		3,473		30	%
Add:
Depreciation and amortization	2,219		2,168
Segment adjusted EBITDA	$	4,600	$	6,536	(30	)%

Three months ended March 31, 2016. Segment adjusted EBITDA decreased $1.9 million during 2016 reflecting:


•	the impact of a decrease in volume throughput which translated into lower gathering services and related fees revenue.


•	an increase in operation and maintenance primarily as a result of expenses associated with repairs to rights-of-way.

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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, interest expense and deferred purchase price obligation income or expense. Items to note follow.



	Corporate
	Three months ended March 31,			Percentage Change
	2016		2015	2016 v. 2015

	(In thousands)
Costs and expenses:
General and administrative	9,563		7,991	20	%
Transaction costs	1,174		110	*
Interest expense (1)	15,882		14,904	7	%
Deferred purchase price obligation expense	(7,463	)	—	*

__________

* Not considered meaningful

(1) Includes interest expense on debt that had been allocated to the 2016 Drop Down Assets during the common control period. See Note 2 to the unaudited condensed consolidated financial statements for more information.

General and Administrative. In the first quarter of 2015, we discontinued allocating certain administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments. As a result, general and administrative expense in the first quarter of 2015 was higher for our operating segments that were not part of or affected by the 2016 Drop Down. With respect to the Contributed Entities, first quarter 2015 general and administrative expense allocations included items that SMLP was no longer allocating to its then-operating segments. With respect to the first quarter of 2016, the decision to discontinue the expense allocations noted above resulted in an increase in corporate general and administrative for allocations that were retained for the full quarter for Polar and Divide and for the period from March 3, 2016 to March 31, 2016 for the Contributed Entities.

Transaction Costs. Transaction costs recognized in 2016 primarily relate to financial and legal advisory costs associated 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, deferred purchase price obligation 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.


•	Distributable Cash Flow. We define distributable cash flow as adjusted EBITDA plus cash interest received and cash taxes 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

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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.


•	Deferred purchase price obligation expense represents the change in the present value of the deferred purchase price obligation. See Notes 2 and 16 to the unaudited condensed consolidated financial statements 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 unaudited condensed 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 unaudited condensed 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

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the date that the respective drop down closed. See Notes 1 and 16 to the unaudited condensed 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.

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



	Three months ended March 31,
	2016			2015
	(In thousands)
Reconciliation of net loss to EBITDA, adjusted EBITDA and distributable cash flow:
Net loss	$	(3,665	)	$	(2,485	)
Add:
Interest expense	15,882			14,904
Deferred purchase price obligation expense	7,463			—
Income tax expense	—			430
Depreciation and amortization	27,865			25,781
Less:
Interest income	22			1
Income tax benefit	77			—
EBITDA	$	47,446		$	38,629
Add:
Proportional adjusted EBITDA for equity method investees	12,388			5,263
Adjustments related to MVC shortfall payments	11,142			12,333
Unit-based and noncash compensation	1,956			1,563
Less:
Income (loss) from equity method investees	2,860			(3,768		)
Gain on asset sales	63			—
Adjusted EBITDA	$	70,009		$	61,556
Add:
Cash interest received	22			1
Cash taxes received	77			—
Less:
Cash interest paid	25,164			25,464
Senior notes interest adjustment	(9,750		)	(11,171		)
Maintenance capital expenditures	3,156			4,506
Distributable cash flow	$	51,538		$	42,758

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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.



	Three months ended March 31,
	2016			2015
	(In thousands)
Reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow:
Net cash provided by operating activities	$	66,849		$	47,663
Add:
Income (loss) from equity method investees	2,860			(3,768		)
Interest expense, excluding deferred loan costs	14,977			13,796
Income tax expense	—			430
Changes in operating assets and liabilities	(23,444		)	(11,079		)
Gain on asset sales	63			—
Less:
Unit-based and noncash compensation	1,956			1,563
Distributions from equity method investees	11,804			6,849
Interest income	22			1
Income tax benefit	77			—
EBITDA	$	47,446		$	38,629
Add:
Loss from equity method investees
Proportional adjusted EBITDA for equity method investees	12,388			5,263
Adjustments related to MVC shortfall payments	11,142			12,333
Unit-based and noncash compensation	1,956			1,563
Less:
Income from equity method investees	2,860			(3,768		)
Gain on asset sales	63			—
Adjusted EBITDA	$	70,009		$	61,556
Add:
Cash interest received	22			1
Cash taxes received	77			—
Less:
Cash interest paid	25,164			25,464
Senior notes interest adjustment	(9,750		)	(11,171		)
Maintenance capital expenditures	3,156			4,506
Distributable cash flow	$	51,538		$	42,758

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.

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Capital Markets Activity

We had no capital markets activity during the three months ended March 31, 2016. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2015 Annual Report.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured revolving credit facility. The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of the assets of Summit Holdings and its subsidiaries are pledged as collateral under the revolving credit facility. The revolving credit facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. As of March 31, 2016, the outstanding balance of the revolving credit facility was $721.0 million and the unused portion totaled $529.0 million. As of March 31, 2016, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the first quarter of 2016.

Senior Notes. In July 2014, the Co-Issuers co-issued the 5.5% senior notes and in June 2013, they co-issued the 7.5% senior notes. 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 the first quarter of 2016 on either series of senior notes.

For additional information on our revolving credit facility and senior notes, see Note 8 to the unaudited condensed 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:



	Three months ended March 31,
	2016			2015
	(In thousands)
Net cash provided by operating activities	$	66,849		$	47,663
Net cash used in investing activities	(437,348		)	(80,241		)
Net cash provided by financing activities	361,793			20,726
Net change in cash and cash equivalents	$	(8,706	)	$	(11,852	)

Operating activities. Cash flows from operating activities increased by $19.2 million in 2016 primarily due to prior-year cash payments associated with environmental remediation costs for Meadowlark Midstream and an increase in distributions from Ohio Gathering.

Investing activities. Cash flows used in investing activities in 2016 were related primarily to the 2016 Drop Down.

Cash flows used in investing activities in 2015 were related primarily to (i) the ongoing expansion of the Polar and Divide system, (ii) expansion of compression capacity on the Bison Midstream system, (iii) pipeline construction projects to connect new receipt points on the Grand River and Bison Midstream systems and (iv) the settlement of the working capital adjustment associated with the Red Rock Drop Down.

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

Net cash used in financing activities in 2016 was primarily composed of the following:


•	Net borrowings under our revolving credit facility to fund the 2016 Drop Down; and


•	Distributions declared in respect of the fourth quarter of 2015 (paid in the first quarter of 2016) and paid in 2016.

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Net cash provided by financing activities in 2015 was primarily composed of the following:


•	Distributions declared in respect of the fourth quarter of 2014 (paid in the first quarter of 2015) and


•	Net repayments under our revolving credit facility.

Contractual Obligations Update

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 unaudited condensed 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.



	Three months ended March 31,
	2016		2015
	(In thousands)
Capital expenditures:
Utica Shale	$	34,988	$	22,565
Williston Basin	18,034		18,310
Piceance/DJ Basins	5,824		6,808
Barnett Shale	563		893
Marcellus Shale	1,738		496
Total reportable segment capital expenditures	61,147		49,072
Corporate	179		398
Total capital expenditures	$	61,326	$	49,470

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


•	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 three months ended March 31, 2016, SMLP recorded total capital expenditures of $61.3 million, which included $3.2 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 existing $1.25 billion revolving credit facility, which had $529.0 million of available capacity at March 31, 2016, together with financial support from our Sponsor and/or access to the debt and equity capital markets, will be adequate to finance our growth strategy for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

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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 Note 11 to the unaudited condensed 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 customers' wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers' 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 three months ended March 31, 2016 follow.



	Williston Basin		Barnett Shale		Piceance/DJ Basins		Total
	(In thousands)
Adjustments related to MVC shortfall payments:
Net change in deferred revenue for MVC shortfall payments (1)	$	235	$	—	$	1,238	$	1,473
Expected MVC shortfall payments (2)	3,301		89		6,279		9,669
Total adjustments related to MVC shortfall payments	$	3,536	$	89	$	7,517	$	11,142

__________

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

(2) As of March 31, 2016, accounts receivable included $4.4 million of total shortfall payment billings, of which $1.6 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 unaudited condensed consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the three months ended March 31, 2016.

Critical Accounting Estimates

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

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There have been no changes in the accounting methodology for items that we have identified as critical accounting estimates and no updates or additions to critical accounting estimates during the three months ended March 31, 2016, except as noted below.

Recognition and Impairment of Long-Lived Assets

Goodwill. As of December 31, 2015, our preliminary estimates of the fair values of the identified assets and liabilities calculated in the step two testing of the Grand River and Polar and Divide reporting units indicated that all of the associated goodwill had been impaired. In the first quarter of 2016, we finalized our calculations of the fair values of the identified assets and liabilities, confirming the preliminary goodwill impairments of $45.5 million for Grand River and $203.4 million for Polar and Divide. For additional information, see Note 6 to the consolidated financial statements included in the 2015 Annual Report.

For additional information regarding critical accounting estimates generally, see the "Critical Accounting Estimates" section of MD&A included in the 2015 Annual Report.

Deferred Purchase Price Obligation

We recognized a deferred purchase price obligation to reflect the expected value of the remaining consideration to be paid in 2020 for the acquisition of the 2016 Drop Down Assets. The calculation of the remaining consideration incorporates estimates of (i) capital expenditures made between Initial Close and December 31, 2019 and (ii) Business Adjusted EBITDA, an income-based measure as defined in the Contribution Agreement, during the period from Initial Close to December 31, 2019. The calculation of the remaining consideration represents management's best estimate of these two financial measures. We then discount the remaining consideration using a commensurate risk-adjusted discount rate and recognize the present value on our balance sheets with the change in present value recognized in earnings in the period of change.

The estimates and expectations used in the remaining consideration calculation and the related present value calculation involve a significant amount of judgment as the results are based on future events and/or conditions, including (i) sales prices, (ii) estimates of future volume throughput, capital expenditures, operating costs and their timing and (iii) economic and regulatory climates, among other factors. Our estimates of these inputs are inherently imprecise because they reflect our expectation of future conditions that are largely outside of our control. While the assumptions used are consistent with our current business plans and investment decisions, these assumptions could change significantly during the period leading up to settlement of the deferred purchase price obligation. See Note 16 to the unaudited condensed consolidated financial statements for additional information.

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;

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•	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;


•	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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our debt portfolio. As of March 31, 2016, we had $600.0 million of fixed-rate senior notes and $721.0 million of variable rate debt (see Note 9 to the unaudited condensed consolidated financial statements for additional information). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our revolving credit facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current

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interest rate risk exposure has not changed materially since December 31, 2015. See the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2015 Annual Report for additional information.

Commodity Price Risk

We currently generate a substantial majority of our revenues pursuant to primarily long-term and fee-based natural gas gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system, (iii) the sale of condensate volumes that we retain on the Grand River system and (iv) the sale of processed natural gas and NGLs pursuant to our percent-of-proceeds contracts with certain of our customers on the Bison Midstream and Grand River systems. Our current commodity price risk exposure has not changed materially since December 31, 2015. See the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2015 Annual Report for additional information.

Item 4. Controls and Procedures.

Under the direction of our general partner's Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of March 31, 2016 and (ii) no change in internal control over financial reporting occurred during the quarter ended March 31, 2016, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings. In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted below.

In 2015, the U.S. Department of Justice issued grand jury subpoenas to Summit Investments, the Partnership and our general partner requesting certain materials related to an incident involving a produced water disposal pipeline owned by Meadowlark Midstream that resulted in a discharge of materials into the environment. On June 19, 2015, 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. On March 3, 2016, the Partnership agreed to acquire, among other things, substantially all of the issued and outstanding membership interests of Meadowlark Midstream from an indirect, wholly owned subsidiary of Summit Investments in connection with the 2016 Drop Down. See Note 16 for additional information regarding this transaction. 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 associated with the above described incident. While we cannot predict the ultimate outcome of this matter with certainty, we believe at this time that it is not likely that the Partnership or our general partner will be subject to any material liability as a result of any governmental proceeding related to the incident.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of the 2015 Annual Report are incorporated herein by reference except to the extent they address risks arising from or relating to the failure of events described therein to occur, which events have since occurred. Risk Factors that have changed materially are set forth below.

Crude oil and natural gas production in certain areas in which we operate may be adversely affected by seasonal weather conditions which in turn could negatively impact the operations of our gathering, treating and processing facilities and our construction of additional facilities.

Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Ohio and West Virginia, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. The result of these types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering, treating and processing systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations.

We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in mountainous areas such as our Utica and Marcellus operations, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant capital expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damages to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines.

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

We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of the Federal Energy Regulatory Commission ("FERC"), the Natural Gas Act ("NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). Interstate movements of crude oil on Polar Midstream’s Little Muddy Pipeline in North Dakota are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”). We are also generally subject

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to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC's regulations thereunder, which authorize FERC to impose fines of up to $1,000,000 per day per violation of the NGA or its implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. The Federal Trade Commission is also authorized to seek fines of up to $1,000,000 per violation. The Commodity Futures Trading Commission (the "CFTC") is directed under the Commodity Exchange Act, to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the "Dodd-Frank Act"), and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per violation or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the Commodity Exchange Act.

The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our natural gas gathering operations or crude oil operations beyond the Little Muddy pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases of Equity Securities. We made no repurchases of our common units during the quarter ended March 31, 2016.

Sponsor Purchases of Equity Securities. The table below presents common units which Energy Capital Partners acquired through its affiliates via open market transactions during the three months ended March 31, 2016.



	(a) Total Number of Common Units Purchased	(b) Average Price Paid Per Common Unit		(c) Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number (or Approximate Dollar Value) of Common Units That May Yet Be Purchased Under the Plans or Programs (1)
January 1 - 31, 2016	1,327,619	$	17.06	1,327,619	$	72,264,365
February 1 - 29, 2016	1,526,284	$	15.36	1,526,284	$	48,844,774
March 1 - 31, 2016	2,005,257	$	14.79	2,005,257	$	19,230,681

__________

(1) In December 2015, Energy Capital Partners approved the Purchase Program. See the 2015 Annual Report for additional information on our Sponsor and the Purchase Program.

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Item 6. Exhibits.



Exhibit number		Description
3.1		First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.2		Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1		Second Amended and Restated Employment Agreement, dated February 1, 2016, and effective February 1, 2016, by and between Summit Midstream Partners, LLC and Brock Degeyter (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form 8-K filed February 2, 2016 (Commission File No. 001-35666))
10.2		Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated as of February 25, 2016 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form 8-K filed March 1, 2016 (Commission File No. 001-35666))
10.3		Second Amendment to Second Amended And Restated Credit Agreement dated as of February 25, 2016 (Incorporated herein by reference to Exhibit 10.2 to SMLP's Form 8-K filed March 1, 2016 (Commission File No. 001-35666))
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Executive Vice President and Chief Financial Officer
32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, and Matthew S. Harrison, Executive Vice President and Chief Financial Officer
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 Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, formatted in XBRL: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Consolidated Statements of Operations, (iii) Unaudited Condensed Consolidated Statements of Partners' Capital, (iv) Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Notes to Unaudited Condensed Consolidated Financial Statements.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	Summit Midstream Partners, LP
	(Registrant)

	By: Summit Midstream GP, LLC (its general partner)

May 9, 2016	/s/ Matthew S. Harrison
	Matthew S. Harrison, Executive Vice President and Chief Financial Officer (Principal Financial Officer)

May 9, 2016	/s/ David K. Kimsey
	David K. Kimsey, Vice President and Chief Accounting Officer (Principal Accounting Officer)