SEC Filing | Summit Midstream Corporation

View:

Download DOC

Download PDF

Download XLS

Download XBRL

Document

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 June 30, 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 July 31, 2016
Common Units		66,588,168 units
General Partner Units		1,354,700 units

TABLE OF CONTENTS



PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	1
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2016 and 2015	2
	Unaudited Condensed Consolidated Statements of Partners' Capital for the six months ended June 30, 2016 and 2015	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 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.	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	61
Item 4.	Controls and Procedures.	62

PART II	OTHER INFORMATION	63
Item 1.	Legal Proceedings.	63
Item 1A.	Risk Factors.	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	63
Item 6.	Exhibits.	63

Table of Contents

Glossary of Terms

adjusted EBITDA: EBITDA plus our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, deferred purchase price obligation expense, 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, 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

Table of Contents

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

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30,		December 31,
	2016		2015
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	6,743	$	21,793
Accounts receivable	48,305		89,581
Other current assets	2,138		3,573
Total current assets	57,186		114,947
Property, plant and equipment, net	1,846,147		1,812,783
Intangible assets, net	441,961		461,310
Investment in equity method investees	711,021		751,168
Goodwill	16,211		16,211
Other noncurrent assets	8,748		8,253
Total assets	$	3,081,274	$	3,164,672

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	21,597	$	40,808
Due to affiliate	183		1,149
Deferred revenue	—		677
Ad valorem taxes payable	7,658		10,271
Accrued interest	17,483		17,483
Accrued environmental remediation	8,026		7,900
Other current liabilities	13,781		13,297
Total current liabilities	68,728		91,585
Long-term debt	1,312,539		1,267,270
Deferred purchase price obligation	532,355		—
Deferred revenue	48,196		45,486
Noncurrent accrued environmental remediation	3,886		5,764
Other noncurrent liabilities	8,031		7,268
Total liabilities	1,973,735		1,417,373
Commitments and contingencies (Note 15)

Common limited partner capital (66,588 units issued and outstanding at June 30, 2016 and 42,063 units issued and outstanding at December 31, 2015)	1,068,680		744,977
Subordinated limited partner capital (0 units issued and outstanding at June 30, 2016 and 24,410 units issued and outstanding at December 31, 2015)	—		213,631
General partner interests (1,355 units issued and outstanding at June 30, 2016 and December 31, 2015)	27,822		25,634
Noncontrolling interest	11,037		—
Summit Investments' equity in contributed subsidiaries	—		763,057
Total partners' capital	1,107,539		1,747,299
Total liabilities and partners' capital	$	3,081,274	$	3,164,672

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

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	76,187		$	69,754		$	154,287		$	138,194
Natural gas, NGLs and condensate sales	8,581			11,967			16,169			24,580
Other revenues	4,867			5,133			9,750			10,167
Total revenues	89,635			86,854			180,206			172,941
Costs and expenses:
Cost of natural gas and NGLs	6,864			8,574			13,154			18,015
Operation and maintenance	23,410			23,595			49,252			46,385
General and administrative	12,876			11,632			25,755			23,231
Transaction costs	122			822			1,296			932
Depreciation and amortization	27,963			26,019			55,691			51,549
Loss (gain) on asset sales, net	74			(214		)	11			(214		)
Long-lived asset impairment	569			—			569			—
Total costs and expenses	71,878			70,428			145,728			139,898
Other income	19			—			41			1
Interest expense	(16,035		)	(15,599		)	(31,917		)	(30,503		)
Deferred purchase price obligation expense	(17,465		)	—			(24,928		)	—
(Loss) income before income taxes	(15,724		)	827			(22,326		)	2,541
Income tax (expense) benefit	(360		)	263			(283		)	(167		)
Loss from equity method investees	(34,471		)	(3,486		)	(31,611		)	(7,254		)
Net loss	$	(50,555	)	$	(2,396	)	$	(54,220	)	$	(4,880	)
Less:
Net (loss) income attributable to Summit Investments	—			(5,381		)	2,745			(9,532		)
Net loss attributable to noncontrolling interest	(268		)	—			(224		)	—
Net (loss) income attributable to SMLP	(50,287		)	2,985			(56,741		)	4,652
Less net (loss) income attributable to general partner, including IDRs	935			1,891			2,746			3,459
Net (loss) income attributable to limited partners	$	(51,222	)	$	1,094		$	(59,487	)	$	1,193

(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.77	)	$	0.05		$	(0.89	)	$	0.04
Common unit – diluted	$	(0.77	)	$	0.05		$	(0.89	)	$	0.04
Subordinated unit – basic and diluted				$	(0.03	)				$	(0.01	)

Weighted-average limited partner units outstanding:
Common units – basic	66,587			38,278			66,540			36,369
Common units – diluted	66,587			38,461			66,540			36,477
Subordinated units – basic and diluted				24,410						24,410

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

Table of Contents

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		$	863,789		$	1,830,678
Net income (loss)	715			478			3,459			(9,532		)	(4,880		)
Distributions to unitholders	(38,769		)	(27,462		)	(4,388		)	—			(70,619		)
Unit-based compensation	3,049			—			—			—			3,049
Tax withholdings on vested SMLP LTIP awards	(936		)	—			—			—			(936		)
Issuance of common units, net of offering costs	222,119			—			—			—			222,119
Contribution from general partner	—			—			4,737			—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			286,799			286,799
Purchase of Polar and Divide	—			—			—			(290,000		)	(290,000		)
Excess of acquired carrying value over consideration paid for Polar and Divide	77,423			46,100			2,521			(126,044		)	—
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			13,352			13,352
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			558			558
Class B membership interest noncash compensation	—			—			—			502			502
Partners' capital, June 30, 2015	$	912,661		$	312,269		$	31,005		$	739,424		$	1,995,359

Table of Contents

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	(60,527		)	1,040			2,746			(224		)	2,745			(54,220		)
Distributions to unitholders	(62,475		)	(14,034		)	(5,511		)	—			—			(82,020		)
Unit-based compensation	3,665			—			—			—			—			3,665
Tax withholdings on vested SMLP LTIP awards	(796		)	—			—			—			—			(796		)
Subordinated units conversion	200,637			(200,637		)	—			—			—			—
Purchase of 2016 Drop Down Assets	—			—			—			—			(866,858		)	(866,858		)
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 acquired carrying value over consideration paid for 2016 Drop Down Assets	243,044			—			4,953			—			(247,997		)	—
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	155			—			—			—			130			285
Partners' capital, June 30, 2016	$	1,068,680		$	—		$	27,822		$	11,037		$	—		$	1,107,539

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

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six months ended June 30,
	2016			2015
	(In thousands)
Cash flows from operating activities:
Net loss	$	(54,220	)	$	(4,880	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	55,957			52,012
Amortization of deferred loan costs	1,947			2,196
Deferred purchase price obligation expense	24,928			—
Unit-based and noncash compensation	3,950			3,551
Loss from equity method investees	31,611			7,254
Distributions from equity method investees	24,181			13,869
Loss (gain) on asset sales, net	11			(214		)
Long-lived asset impairment	569			—
Write-off of debt issuance costs	—			727
Changes in operating assets and liabilities:
Accounts receivable	41,276			36,778
Trade accounts payable	1,447			(2,031		)
Due to affiliate	(966		)	5,162
Change in deferred revenue	2,033			5,845
Ad valorem taxes payable	(2,613		)	(2,413		)
Accrued interest	—			(1,375		)
Accrued environmental remediation	(1,752		)	(10,196		)
Other, net	3,141			(1,289		)
Net cash provided by operating activities	131,500			104,996
Cash flows from investing activities:
Capital expenditures	(91,372		)	(131,517		)
Contributions to equity method investees	(15,645		)	(64,396		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(359,431		)	(292,941		)
Other, net	(435		)	238
Net cash used in investing activities	(466,883		)	(488,616		)

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Six months ended June 30,
	2016			2015
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(82,020		)	(70,619		)
Borrowings under revolving credit facility	439,300			257,000
Repayments under revolving credit facility	(50,300		)	(151,000		)
Repayments under term loan	—			(177,500		)
Deferred loan costs	(2,766		)	(136		)
Proceeds from issuance of common units, net	—			222,119
Contribution from general partner	—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	12,214			286,799
Expenses paid by Summit Investments on behalf of contributed subsidiaries	4,821			13,352
Other, net	(916		)	(936		)
Net cash provided by financing activities	320,333			383,816
Net change in cash and cash equivalents	(15,050		)	196
Cash and cash equivalents, beginning of period	21,793			27,811
Cash and cash equivalents, end of period	$	6,743		$	28,007

Supplemental cash flow disclosures:
Cash interest paid	$	31,464		$	30,331
Less capitalized interest	1,779			1,361
Interest paid (net of capitalized interest)	$	29,685		$	28,970

Cash paid for taxes	$	—		$	—

Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	14,322		$	29,357
Issuance of deferred purchase price obligation to affiliate to partially fund the 2016 Drop Down	507,427			—
Capitalized interest allocated from Summit Investments to contributed subsidiaries	223			558
Excess of acquired carrying value over consideration paid and recognized for 2016 Drop Down Assets	247,997			—
Excess of acquired carrying value over consideration paid for Polar and Divide	—			126,044
Distribution of debt related to Carve-Out Financial Statements of Summit Investments (see Notes 2 and 11)	342,926			—

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

Table of Contents

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 various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Midstream Holdings, LLC ("Summit Holdings"), a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

Summit Midstream GP, LLC (the "general partner"), a Delaware limited liability company, manages our operations and activities. Summit Midstream Partners, LLC ("Summit Investments"), a Delaware limited liability company, is the ultimate owner of our general partner and has the right to appoint the entire board of directors of our general partner. Summit Investments is controlled by Energy Capital Partners II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners" 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 June 30, 2016, Summit Investments beneficially owned 29,854,581 SMLP common units.

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

On February 25, 2016, the Partnership and Summit Midstream Partners Holdings, LLC (“SMP Holdings”), a wholly owned subsidiary of Summit Investments, entered into a contribution agreement (the "Contribution Agreement") pursuant to which SMP Holdings agreed to contribute to the Partnership substantially all of its limited partner interest in Summit Midstream OpCo, LP ("OpCo"), a Delaware limited partnership that owns (i) 100% of the issued and outstanding membership interests of Summit Midstream Utica, LLC ("Summit Utica"), Meadowlark Midstream Company, LLC ("Meadowlark Midstream") and Tioga Midstream, LLC ("Tioga Midstream" and collectively with Summit Utica and Meadowlark Midstream, the "Contributed Entities"), each a limited liability company and (ii) a 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively with OpCo and the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down closed on March 3, 2016. Subsequent to closing, SMP Holdings retained a 1.0% noncontrolling interest in OpCo, which is managed by Summit Midstream OpCo GP, LLC ("OpCo GP"), a Delaware limited liability company and a wholly owned subsidiary of Summit Holdings.

Business Operations. We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based agreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather, treat, compress and process as well as by the volumes of crude oil and produced water that we gather. Our gathering systems and the unconventional resource basins in which they operate are as follows:


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


•	Bison Midstream, 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;

Table of Contents


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

Presentation and Consolidation. We prepare our 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 subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. The financial position, results of operations and cash flows of (i) acquired drop down assets, liabilities and expenses or (ii) 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 adjustments, which are necessary to fairly present the unaudited condensed consolidated balance sheet as of June 30, 2016, the unaudited condensed consolidated statements of operations for the three- and six-month periods ended June 30, 2016 and 2015, and the unaudited condensed consolidated statements of partners' capital and cash flows for the six-month periods ended June 30, 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, and as updated and superseded by our current report on Form 8-K dated June 6, 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 for Bison Midstream. As a result of this evaluation, we determined that

Table of Contents

certain amounts that had previously been recognized in cost of natural gas and NGLs would be more appropriately reflected as gathering services and related fees and other revenues to enhance reporting transparency. The impact of these reclassifications, which had no impact on net loss, total partners' capital or segment adjusted EBITDA, follows.



	Three months ended June 30, 2015		Six months ended June 30, 2015
	(In thousands)
Gathering services and related fees	$	3,050	$	6,468
Other revenues	620		1,258
Net impact on total revenues	$	3,670	$	7,726

Cost of natural gas and NGLs	$	3,670	$	7,726
Net impact on total costs and expenses	$	3,670	$	7,726

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 incurred interest expense related to capital projects of assets that have been acquired by the Partnership, the associated interest expense is allocated to the drop down assets as a noncash equity contribution and capitalized into the basis of the asset.

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



	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.

Table of Contents

Other Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the closing of our revolving credit facility and related amendments. We capitalize and then amortize these deferred loan costs over the life of the 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 related to the 2016 Drop Down Assets. 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 SMP Holdings' ownership interest in OpCo. For financial reporting purposes, we consolidate OpCo and its wholly owned subsidiaries with our wholly owned subsidiaries and SMP Holdings' interest is shown as noncontrolling interest in partners' capital. We reflect changes in our ownership of OpCo 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 OpCo (for periods subsequent to the 2016 Drop Down), (ii) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (iii) the general partner's 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.

Table of Contents

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 change to our position regarding ASU 2014-09 during 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, 2018, 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.

•

ASU No. 2016-12 Revenue From Contracts With Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ("ASU No. 2016.12"). ASU No. 2016.12 does not change the core principle of the guidance in Topic 606. Rather, the amendments therein affect only the narrow aspects of Topic 606 including assessing the collectability criterion and issues related to contract modification at transition and

Table of Contents

completed contracts at transition. 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.

3. SEGMENT INFORMATION

As of June 30, 2016, our reportable segments are:


•	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 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 (see Note 7) 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. No other line items in the statements of operations or cash flows, as disclosed in the tables below, include results for our investment in Ohio Gathering.

Corporate represents those assets and liabilities and revenues and expenses that are (i) not specifically attributable to a reportable segment, (ii) not individually reportable, or (iii) that have not been allocated to our reportable segments.

Assets by reportable segment follow.



	June 30, 2016		December 31, 2015
	(In thousands)
Assets:
Utica Shale (1)	$	892,969	$	886,224
Williston Basin	716,926		740,361
Piceance/DJ Basins	819,954		866,095
Barnett Shale	407,667		416,586
Marcellus Shale	229,898		233,116
Total reportable segment assets	3,067,414		3,142,382
Corporate	13,860		22,290
Total assets	$	3,081,274	$	3,164,672

__________

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

Table of Contents

Revenues by reportable segment follow.



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Revenues:
Utica Shale	$	5,403	$	515	$	9,686	$	904
Williston Basin	27,507		23,650		57,517		46,718
Piceance/DJ Basins	29,411		31,083		58,402		61,977
Barnett Shale	20,856		23,823		41,257		47,720
Marcellus Shale	6,458		7,783		13,344		15,622
Total reportable segment revenues and total revenues	$	89,635	$	86,854	$	180,206	$	172,941

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



	Three months ended June 30,			Six months ended June 30,
	2016	2015		2016	2015
Percentage of total revenues:
Counterparty A - Piceance/DJ Basins	*	12	%	*	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 June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Depreciation and amortization:
Utica Shale	$	952	$	217	$	1,796	$	357
Williston Basin	8,410		7,729		16,767		15,096
Piceance/DJ Basins	12,297		11,818		24,570		23,600
Barnett Shale	4,057		4,114		8,113		8,271
Marcellus Shale	2,222		2,169		4,441		4,338
Total reportable segment depreciation and amortization	27,938		26,047		55,687		51,662
Corporate	154		184		270		350
Total depreciation and amortization	$	28,092	$	26,231	$	55,957	$	52,012

Table of Contents

Cash paid for capital expenditures by reportable segment follow.



	Six months ended June 30,
	2016		2015
	(In thousands)
Capital expenditures:
Utica Shale	$	54,064	$	40,195
Williston Basin	21,919		76,470
Piceance/DJ Basins	10,633		11,900
Barnett Shale	2,109		1,922
Marcellus Shale	2,135		637
Total reportable segment capital expenditures	90,860		131,124
Corporate	512		393
Total capital expenditures	$	91,372	$	131,517

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

Segment adjusted EBITDA by reportable segment follows.



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	17,452	$	6,414	$	33,029	$	11,621
Williston Basin	19,209		12,638		38,929		23,615
Piceance/DJ Basins	26,231		28,207		51,046		56,909
Barnett Shale	13,913		15,540		27,990		32,301
Marcellus Shale	4,807		6,162		9,408		12,696
Total of reportable segments’ measures of profit or loss	$	81,612	$	68,961	$	160,402	$	137,142

__________

(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.

Table of Contents

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



	Three months ended June 30,					Six months ended June 30,
	2016			2015		2016			2015
	(In thousands)
Reconciliation of (loss) income before income taxes to total of reportable segments' measure of profit or loss:
(Loss) income before income taxes	$	(15,724	)	$	827	$	(22,326	)	$	2,541
Add:
Allocated corporate expenses	9,247			7,043		18,006			13,666
Interest expense	16,035			15,599		31,917			30,503
Deferred purchase price obligation expense	17,465			—		24,928			—
Depreciation and amortization	28,092			26,231		55,957			52,012
Proportional adjusted EBITDA for equity method investees	12,725			6,552		25,113			11,816
Adjustments related to MVC shortfall payments	11,135			10,935		22,277			23,268
Unit-based and noncash compensation	1,994			1,988		3,950			3,551
Loss on asset sales	77			24		134			24
Long-lived asset impairment	569			—		569			—
Less:
Interest income	—			—		—			1
Gain on asset sales	3			238		123			238
Total of reportable segments’ measures of profit or loss	$	81,612		$	68,961	$	160,402		$	137,142

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.

Adjustments related to MVC shortfall payments by reportable segment follow.



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In thousands)
Adjustments related to MVC shortfall payments:
Williston Basin	$	4,261		$	2,847		$	7,797		$	5,500
Piceance/DJ Basins	7,456			9,866			14,973			19,769
Barnett Shale	(582		)	(1,778		)	(493		)	(2,001		)
Total adjustments related to MVC shortfall payments	$	11,135		$	10,935		$	22,277		$	23,268

4. PROPERTY, PLANT, AND EQUIPMENT, NET

Details on property, plant, and equipment follow.



	June 30, 2016		December 31, 2015
	(In thousands)
Gathering and processing systems and related equipment	$	1,923,234	$	1,883,139
Construction in progress	101,743		75,132
Land and line fill	11,442		11,055
Other	33,552		32,427
Total	2,069,971		2,001,753
Less accumulated depreciation	223,824		188,970
Property, plant, and equipment, net	$	1,846,147	$	1,812,783

Depreciation expense and capitalized interest follow.



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Depreciation expense	$	17,595	$	15,721	$	34,966	$	30,985
Capitalized interest	1,063		834		1,779		1,361

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.



	June 30, 2016
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(10,189	)	$	14,006
Contract intangibles	12.5	426,464		(128,760		)	297,704
Rights-of-way	26.1	152,174		(21,923		)	130,251
Total intangible assets		$	602,833	$	(160,872	)	$	441,961

Unfavorable gas gathering contract	10.0	$	10,962	$	(6,466	)	$	4,496



	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

Table of Contents

We recognized amortization expense in other revenues as follows:



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(317	)	$	(375	)	$	(655	)	$	(801	)
Amortization expense – unfavorable gas gathering contract	188			163			389			338

We recognized amortization expense in costs and expenses as follows:



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Amortization expense – contract intangibles	$	8,854	$	8,835	$	17,708	$	17,670
Amortization expense – rights-of-way	1,514		1,463		3,017		2,894

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



	Amortizing intangible assets		Unfavorable gas gathering contract
	(In thousands)
2016	$	21,607	$	509
2017	42,027		1,047
2018	41,481		1,035
2019	41,726		1,045
2020	44,374		860

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 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 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.

Table of Contents

In January 2014, Summit Investments acquired a 1.0% ownership interest in Ohio Gathering from Blackhawk Midstream, LLC ("Blackhawk") for $190.0 million. Concurrent with this acquisition, Summit Investments made an $8.4 million capital contribution to Ohio Gathering to maintain its 1.0% ownership interest.

The ownership interest Summit Investments acquired from Blackhawk included an option to increase the holder's ownership interest in Ohio Gathering to 40.0% (the "Option"). In May 2014, Summit Investments exercised the Option to increase its ownership to 40.0% (the "Option Exercise") and made the following payments (i) $326.6 million of capital contribution true-ups, (ii) $50.4 million of additional capital contributions to maintain its 40.0% ownership interest, and (iii) $5.4 million of management fee payments that were recognized as capital contributions in its Ohio Gathering capital accounts. Concurrent with and subsequent to the Option Exercise, the non-affiliated owners have retained their respective 60.0% ownership interest in Ohio Gathering (the "Non-affiliated Owners").

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

Summit Investments recognized the $190.0 million that it paid to Blackhawk as an investment in Ohio Gathering at inception. In addition, Ohio Gathering had assigned a value of $7.5 million to the Option, recognized it initially as an asset and concurrently attributed the value of the Option to Blackhawk's capital account. Upon acquiring Blackhawk's interest, the Option was reclassified from Blackhawk's capital account to Summit Investments' capital account in Ohio Gathering's records. Neither of these transactions involved a flow of funds to or from Ohio Gathering. As such, they created a basis difference between its recorded investment in equity method investees and that recognized and attributed to Summit Investments by Ohio Gathering. In accordance with the retrospective recognition triggered by the Option Exercise, in February 2014, Summit Investments began amortizing these basis differences over the weighted-average remaining life of the contracts underlying Ohio Gathering's operations. The impact of amortizing these two basis differences 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 June 30, 2016.

In June 2016, an impairment loss was recognized by the operator of OCC. The Partnership recorded its 40.0% share of the impairment loss, or $37.8 million, in loss from equity method investees in the consolidated statements of operations. Although we recognize activity for Ohio Gathering on a one-month lag, we recorded the impairment loss in May 2016 activity because the information was available to us prior to receiving the full June 2016 financial results.

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



Investment in equity method investees, June 30, 2016	$	711,021
June cash distributions	3,847
Basis difference	(150,213		)
Impairment loss	37,782
Investment in equity method investees, net of basis difference, May 31, 2016	$	602,437

Table of Contents

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



	Three months ended May 31, 2016					Three months ended May 31, 2015
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	38,444	$	5,417		$	26,531	$	831
Total operating expenses	22,572		98,748			23,755		3,881
Net income (loss)	15,868		(93,701		)	2,776		(3,315		)



	Six months ended May 31, 2016					Six months ended May 31, 2015
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	76,243	$	10,615		$	50,182	$	860
Total operating expenses	45,105		103,307			46,327		6,066
Net income (loss)	31,137		(93,245		)	3,856		(5,472		)

8. DEFERRED REVENUE

A rollforward of current deferred revenue follows.



	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2016	$	—	$	—	$	677	$	677
Additions	—		5,484		—		5,484
Less revenue recognized	—		5,484		677		6,161
Current deferred revenue, June 30, 2016	$	—	$	—	$	—	$	—

A rollforward of noncurrent deferred revenue follows.



	Williston Basin		Piceance/DJ Basins		Barnett Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2016	$	29,002	$	16,484	$	—	$	45,486
Additions	235		2,475		—		2,710
Less revenue recognized	—		—		—		—
Noncurrent deferred revenue, June 30, 2016	$	29,237	$	18,959	$	—	$	48,196

As of June 30, 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.

Table of Contents

9. DEBT

Debt consisted of the following:



	June 30, 2016			December 31, 2015
	(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (2.97% at June 30, 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
Unamortized deferred loan costs (2)	(3,826		)	(4,139		)
Summit Holdings 7.50% Senior unsecured notes due July 2021	300,000			300,000
Unamortized deferred loan costs (2)	(4,635		)	(5,091		)
Total long-term debt	$	1,312,539		$	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 March 3, 2016 closing of the 2016 Drop Down. In connection with this amendment, (i) the revolving credit facility's borrowing capacity increased from $700.0 million to $1.25 billion, (ii) a new investment basket allowing the Co-Issuers (as defined below) to buy back up to $100.0 million of our outstanding senior unsecured notes was included, (iii) the total leverage ratio was increased to 5.50 to 1.0 through December 31, 2016, and (iv) various amendments were approved to facilitate the 2016 Drop Down. 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 other than OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream ("Non-Guarantor 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 June 30, 2016, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 2.97% 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 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 June 30, 2016, we were in compliance with the revolving credit facility's covenants. There were no defaults or events of default during the six months ended June 30, 2016.

Table of Contents

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").

Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream Services and OpCo GP (collectively, the "Guarantor Subsidiaries") and SMLP have fully and unconditionally and jointly and severally guaranteed the 5.5% senior notes and the 7.5% senior notes (collectively, the "Senior Notes")(see Note 17). The Senior Notes have not been guaranteed by the Co-Issuers or the Non-Guarantor Subsidiaries. The Non-Guarantor Subsidiaries were previously guarantors of the Senior Notes. On August 5, 2016, a consent and waiver agreement to the revolving credit facility was executed to remove the guarantees of the entities that now comprise the Non-Guarantor Subsidiaries group effective March 30, 2016. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013.

As of June 30, 2016, we were in compliance with the covenants of the Senior Notes. There were no defaults or events of default during the six months ended June 30, 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 46% of total accounts receivable at June 30, 2016, compared with 68% as of December 31, 2015.

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

The deferred purchase price obligation's carrying value is its fair value because carrying value represents the present value of the payment expected to be made in 2020. Our calculation of the 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).

The rollforward of the Level 3 liabilities measured at fair value on a recurring basis follows (in thousands).



Level 3 liabilities, January 1, 2016	$	—
Additions	507,427
Change in fair value	24,928
Level 3 liabilities, June 30, 2016	$	532,355

Table of Contents

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



	June 30, 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)	296,174		257,500		295,861		224,000
7.5% Senior notes ($300.0 million principal)	295,365		284,375		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 June 30, 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	115,674	—		—	115,674
Subordinated unit conversion	24,409,850	(24,409,850	)	—	—
Units, June 30, 2016	66,588,168	—		1,354,700	67,942,868

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 OpCo and its subsidiaries as a noncontrolling interest in the consolidated financial statements.

Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of the 2016 Drop Down Assets and Polar and Divide that have 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. Net income or loss was attributed to Summit Investments for:


•	the 2016 Drop Down Assets during the six months ended June 30, 2016 and the three and six months ended June 30, 2015 and


•	Polar and Divide during the three and six months ended June 30, 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

Table of Contents

Note 16). In June 2016, we received a working capital adjustment of $0.6 million from a subsidiary of Summit Investments. We recognized a capital contribution from Summit Investments for the difference between (i) the net cash consideration paid and the deferred purchase price obligation and (ii) Summit Investments' net investment in the 2016 Drop Down Assets.

The calculation of the capital 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
Working capital adjustment received from a subsidiary of Summit Investments	(569		)
Total consideration paid and recognized by SMLP				866,858
Excess of acquired carrying value over consideration paid and recognized				$	247,997

Allocation of capital contribution:
General partner interest	$	4,953
Common limited partner interest	243,044
Partners' capital contribution – excess of acquired carrying value over consideration paid and recognized				$	247,997

Cash Distributions Paid and Declared. We paid the following per-unit distributions during the three and six months ended June 30:



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Per-unit distributions to unitholders	$	0.575	$	0.565	$	1.150	$	1.125

On July 21, 2016, the board of directors of our general partner declared a distribution of $0.575 per unit for the quarterly period ended June 30, 2016. This distribution, which totaled $41.0 million, will be paid on August 12, 2016 to unitholders of record at the close of business on August 5, 2016. We allocated the August 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 and six months ended June 30 follow.



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
IDR payments	$	1,938	$	1,534	$	3,874	$	2,976

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 June 30,						Six months ended June 30,
	2016			2015			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	$	(51,222	)	$	1,847		$	(59,487	)	$	1,490
Net income attributable to subordinated units (1)				(753		)				(297		)
Net (loss) income attributable to limited partners	$	(51,222	)	$	1,094		$	(59,487	)	$	1,193

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	66,587			38,278			66,540			36,369
Effect of nonvested phantom units	—			183			—			108
Weighted-average common units outstanding – diluted	66,587			38,461			66,540			36,477

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

(Loss) earnings per limited partner unit:
Common unit – basic	$	(0.77	)	$	0.05		$	(0.89	)	$	0.04
Common unit – diluted	$	(0.77	)	$	0.05		$	(0.89	)	$	0.04
Subordinated unit – basic and diluted (1)				$	(0.03	)				$	(0.01	)

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU	4			—			250			95

__________

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

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 June 30, 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 Profits Interests' noncash compensation expense that had been allocated to the contributed subsidiaries prior to their respective drop down date due to common control.

Table of Contents

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



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
SMP Net Profits Interests noncash compensation	$	90	$	251	$	285	$	502

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 June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Operation and maintenance expense	$	6,623	$	6,472	$	13,372	$	12,946
General and administrative expense	7,679		7,087		15,457		14,222

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 June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(In thousands)
Rent expense	$	745	$	683	$	1,361	$	1,189

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

Table of Contents

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. Based on available information, Summit Investments accounted for the rupture as a 2014 event and recognized an environmental remediation accrual.

The incident, which is covered by Summit Investments' insurance policies, exhausted Summit Investments' $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. Details of the accrual recognized follow.



	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	(1,752		)
Accrued environmental remediation, June 30, 2016	$	11,912

As of June 30, 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 June 30, 2017. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

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

16. ACQUISITIONS AND DROP DOWN TRANSACTIONS

2016 Drop Down. On March 3, 2016, the Partnership acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets (see Note 1). These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin as well as ownership interests in a natural gas gathering system and a condensate stabilization facility, both located in the Utica Shale.

The net consideration paid and recognized in connection with the 2016 Drop Down (i) consisted of a cash payment to SMP Holdings of $360.0 million funded with borrowings under our revolving credit facility and a $0.6 million working capital adjustment received in June 2016 (the “Initial Payment”)(see Note 11) and (ii) includes a deferred payment in 2020 (the “Deferred Purchase Price Obligation”).

Table of Contents

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 March 3, 2016 and December 31, 2019;


•	plus all Business Adjusted EBITDA from the 2016 Drop Down Assets between March 3, 2016 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 June 30, 2016, the net present value of this obligation was $532.4 million and has been recorded on the consolidated balance sheet. Deferred purchase price obligation expense is recognized in the statements of operations. 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 for all periods in which common control existed. Subsequent to closing the 2016 Drop Down, SMLP’s financial results retrospectively include the combined financial results of the 2016 Drop Down Assets for all common-control periods.

Table of Contents

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 June 30, 2015			Six months ended June 30,
	Three months ended June 30, 2015			2016			2015
	(In thousands)
SMLP revenues	$	76,253		$	171,339		$	148,888
2016 Drop Down Assets revenues	5,910			8,867			10,780
Polar and Divide revenues (1)	4,691						13,273
Combined revenues	$	86,854		$	180,206		$	172,941

SMLP net (loss) income	$	2,985		$	(56,965	)	$	4,652
2016 Drop Down Assets net income (loss)	(7,438		)	2,745			(14,935		)
Polar and Divide net income (1)	2,057						5,403
Combined net loss	$	(2,396	)	$	(54,220	)	$	(4,880	)

__________

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

Table of Contents

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

The following supplemental condensed consolidating financial information reflects SMLP's separate accounts, the combined accounts of the Co-Issuers, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries and the consolidating adjustments for the dates and periods indicated. For purposes of the following consolidating information, each of SMLP and Co-Issuers account for their subsidiary investments, if any, under the equity method of accounting.

Table of Contents

Condensed Consolidating Balance Sheets. Balance sheets as of June 30, 2016 and December 31, 2015 follow.



	June 30, 2016
	SMLP		Co-Issuers		Guarantor subsidiaries		Non-guarantor subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	2,320	$	638	$	2,351	$	1,434	$	—		$	6,743
Accounts receivable	55		—		40,698		7,552		—			48,305
Due from affiliate	11,660		140,443		300,806		—		(452,909		)	—
Other current assets	838		—		1,162		138		—			2,138
Total current assets	14,873		141,081		345,017		9,124		(452,909		)	57,186
Property, plant and equipment, net	1,419		—		1,453,815		390,913		—			1,846,147
Intangible assets, net	—		—		417,381		24,580		—			441,961
Investment in equity method investees	—		—		—		711,021		—			711,021
Goodwill	—		—		16,211		—		—			16,211
Other noncurrent assets	2,402		6,186		160		—		—			8,748
Investment in subsidiaries	2,070,570		3,253,326		—		—		(5,323,896		)	—
Total assets	$	2,089,264	$	3,400,593	$	2,232,584	$	1,135,638	$	(5,776,805	)	$	3,081,274

Liabilities and Partners' Capital
Trade accounts payable	$	334	$	—	$	8,530	$	12,733	$	—		$	21,597
Due to affiliate	441,432		—		—		11,660		(452,909		)	183
Ad valorem taxes payable	20		—		6,965		673		—			7,658
Accrued interest	—		17,483		—		—		—			17,483
Accrued environmental remediation	—		—		—		8,026		—			8,026
Other current liabilities	4,573		—		7,836		1,372		—			13,781
Total current liabilities	446,359		17,483		23,331		34,464		(452,909		)	68,728
Long-term debt	—		1,312,539		—		—		—			1,312,539
Deferred purchase price obligation	532,355		—		—		—		—			532,355
Deferred revenue	—		—		48,196		—		—			48,196
Noncurrent accrued environmental remediation	—		—		—		3,886		—			3,886
Other noncurrent liabilities	3,011		—		5,000		20		—			8,031
Total liabilities	981,725		1,330,022		76,527		38,370		(452,909		)	1,973,735

Total partners' capital	1,107,539		2,070,571		2,156,057		1,097,268		(5,323,896		)	1,107,539
Total liabilities and partners' capital	$	2,089,264	$	3,400,593	$	2,232,584	$	1,135,638	$	(5,776,805	)	$	3,081,274

Table of Contents



	December 31, 2015
	SMLP		Co-Issuers		Guarantor subsidiaries		Non-guarantor subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	73	$	12,407	$	6,930	$	2,383	$	—		$	21,793
Accounts receivable	—		—		84,021		5,560		—			89,581
Due from affiliate	3,168		151,443		207,651		—		(362,262		)	—
Other current assets	540		—		2,672		361		—			3,573
Total current assets	3,781		163,850		301,274		8,304		(362,262		)	114,947
Property, plant and equipment, net	1,178		—		1,462,623		348,982		—			1,812,783
Intangible assets, net	—		—		438,093		23,217		—			461,310
Investment in equity method investees	—		—		—		751,168		—			751,168
Goodwill	—		—		16,211		—		—			16,211
Other noncurrent assets	3,480		4,611		162		—		—			8,253
Investment in subsidiaries	2,438,395		3,222,187		—		—		(5,660,582		)	—
Total assets	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672

Liabilities and Partners' Capital
Trade accounts payable	$	482	$	—	$	18,489	$	21,837	$	—		$	40,808
Due to affiliate	360,243		—		—		3,168		(362,262		)	1,149
Deferred revenue	—		—		677		—		—			677
Ad valorem taxes payable	9		—		9,881		381		—			10,271
Accrued interest	—		17,483		—		—		—			17,483
Accrued environmental remediation	—		—		—		7,900		—			7,900
Other current liabilities	4,558		—		7,405		1,334		—			13,297
Total current liabilities	365,292		17,483		36,452		34,620		(362,262		)	91,585
Long-term debt	332,500		934,770		—		—		—			1,267,270
Deferred revenue	—		—		45,486		—		—			45,486
Noncurrent accrued environmental remediation	—		—		—		5,764		—			5,764
Other noncurrent liabilities	1,743		—		5,503		22		—			7,268
Total liabilities	699,535		952,253		87,441		40,406		(362,262		)	1,417,373

Total partners' capital	1,747,299		2,438,395		2,130,922		1,091,265		(5,660,582		)	1,747,299
Total liabilities and partners' capital	$	2,446,834	$	3,390,648	$	2,218,363	$	1,131,671	$	(6,022,844	)	$	3,164,672

Table of Contents

Condensed Consolidating Statements of Operations. For the purposes of the following condensed consolidating statements of operations, we allocate general and administrative expenses recognized at the SMLP parent to the Guarantor Subsidiaries and Other Subsidiaries to reflect what those entities results would have been had they operated on a stand-alone basis. Statements of operations for the three and six months ended June 30, 2016 and 2015 follow.



	Three months ended June 30, 2016
	SMLP			Co-Issuers			Guarantor subsidiaries		Non-guarantor subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	62,677	$	13,510		$	—	$	76,187
Natural gas, NGLs and condensate sales	—			—			8,581		—			—		8,581
Other revenues	—			—			4,306		561			—		4,867
Total revenues	—			—			75,564		14,071			—		89,635
Costs and expenses:
Cost of natural gas and NGLs	—			—			6,864		—			—		6,864
Operation and maintenance	—			—			21,042		2,368			—		23,410
General and administrative	—			—			10,761		2,115			—		12,876
Transaction costs	122			—			—		—			—		122
Depreciation and amortization	154			—			24,757		3,052			—		27,963
Loss on asset sales, net	—			—			74		—			—		74
Long-lived asset impairment	—			—			40		529			—		569
Total costs and expenses	276			—			63,538		8,064			—		71,878
Other income	19			—			—		—			—		19
Interest expense	—			(16,035		)	—		—			—		(16,035		)
Deferred purchase price obligation expense	(17,465		)	—			—		—			—		(17,465		)
(Loss) income before income taxes	(17,722		)	(16,035		)	12,026		6,007			—		(15,724		)
Income tax expense	(360		)	—			—		—			—		(360		)
Loss from equity method investees	—			—			—		(34,471		)	—		(34,471		)
Equity in loss of consolidated subsidiaries	(32,473		)	(16,438		)	—		—			48,911		—
Net (loss) income	$	(50,555	)	$	(32,473	)	$	12,026	$	(28,464	)	$	48,911	$	(50,555	)

Table of Contents



	Three months ended June 30, 2015
	SMLP			Co-Issuers			Guarantor subsidiaries			Non-guarantor subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	64,420		$	5,334		$	—		$	69,754
Natural gas, NGLs and condensate sales	—			—			11,967			—			—			11,967
Other revenues	—			—			4,556			577			—			5,133
Total revenues	—			—			80,943			5,911			—			86,854
Costs and expenses:
Cost of natural gas and NGLs	—			—			8,574			—			—			8,574
Operation and maintenance	—			—			21,618			1,977			—			23,595
General and administrative				—			9,739			1,893			—			11,632
Transaction costs	822			—			—			—			—			822
Depreciation and amortization	184			—			23,795			2,040			—			26,019
Gain on asset sales, net	—			—			(214		)	—			—			(214		)
Total costs and expenses	1,006			—			63,512			5,910			—			70,428
Other income	—			—			—			—			—			—
Interest expense	(3,516		)	(12,083		)	—			—			—			(15,599		)
(Loss) income before income taxes	(4,522		)	(12,083		)	17,431			1			—			827
Income tax benefit	263			—			—			—			—			263
Loss from equity method investees	—			—			—			(3,486		)	—			(3,486		)
Equity in earnings of consolidated subsidiaries	1,863			13,946			—			—			(15,809		)	—
Net (loss) income	$	(2,396	)	$	1,863		$	17,431		$	(3,485	)	$	(15,809	)	$	(2,396	)

Table of Contents



	Six months ended June 30, 2016
	SMLP			Co-Issuers			Guarantor subsidiaries		Non-guarantor subsidiaries			Consolidating adjustments		Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	127,445	$	26,842		$	—	$	154,287
Natural gas, NGLs and condensate sales	—			—			16,169		—			—		16,169
Other revenues	—			—			8,674		1,076			—		9,750
Total revenues	—			—			152,288		27,918			—		180,206
Costs and expenses:
Cost of natural gas and NGLs	—			—			13,154		—			—		13,154
Operation and maintenance	—			—			43,614		5,638			—		49,252
General and administrative	—			—			20,891		4,864			—		25,755
Transaction costs	1,296			—			—		—			—		1,296
Depreciation and amortization	270			—			49,429		5,992			—		55,691
Loss on asset sales, net	—			—			11		—			—		11
Long-lived asset impairment	—			—			41		528			—		569
Total costs and expenses	1,566			—			127,140		17,022			—		145,728
Other income	41			—			—		—			—		41
Interest expense	(1,441		)	(30,476		)	—		—			—		(31,917		)
Deferred purchase price obligation expense	(24,928		)	—			—		—			—		(24,928		)
(Loss) income before income taxes	(27,894		)	(30,476		)	25,148		10,896			—		(22,326		)
Income tax expense	(283		)	—			—		—			—		(283		)
Loss from equity method investees	—			—			—		(31,611		)	—		(31,611		)
Equity in (loss) earnings of consolidated subsidiaries	(26,043		)	4,433			—		—			21,610		—
Net (loss) income	$	(54,220	)	$	(26,043	)	$	25,148	$	(20,715	)	$	21,610	$	(54,220	)

Table of Contents



	Six months ended June 30, 2015
	SMLP			Co-Issuers			Guarantor subsidiaries			Non-guarantor subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	128,605		$	9,589		$	—		$	138,194
Natural gas, NGLs and condensate sales	—			—			24,580			—			—			24,580
Other revenues	—			—			8,975			1,192			—			10,167
Total revenues	—			—			162,160			10,781			—			172,941
Costs and expenses:
Cost of natural gas and NGLs	—			—			18,015			—			—			18,015
Operation and maintenance	—			—			42,673			3,712			—			46,385
General and administrative	—			—			19,765			3,466			—			23,231
Transaction costs	932			—			—			—			—			932
Depreciation and amortization	350			—			47,384			3,815			—			51,549
Gain on asset sales, net	—			—			(214		)	—			—			(214		)
Total costs and expenses	1,282			—			127,623			10,993			—			139,898
Other income	—			—			1			—			—			1
Interest expense	(6,302		)	(24,201		)	—			—			—			(30,503		)
(Loss) income before income taxes	(7,584		)	(24,201		)	34,538			(212		)	—			2,541
Income tax expense	(167		)	—			—			—			—			(167		)
Loss from equity method investees	—			—			—			(7,254		)	—			(7,254		)
Equity in earnings of consolidated subsidiaries	2,871			27,072			—			—			(29,943		)	—
Net (loss) income	$	(4,880	)	$	2,871		$	34,538		$	(7,466	)	$	(29,943	)	$	(4,880	)

Table of Contents

Condensed Consolidating Statements of Cash Flows. Statements of cash flows for the six months ended June 30, 2016 and 2015 follow.



	Six months ended June 30, 2016
	SMLP			Co-Issuers			Guarantor subsidiaries			Non-guarantor subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	750		$	(28,517	)	$	119,435		$	39,832		$	—		$	131,500

Cash flows from investing activities:
Capital expenditures	(512		)	—			(30,745		)	(60,115		)	—			(91,372		)
Contributions to equity method investees	—			—			—			(15,645		)	—			(15,645		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(359,431		)	—			—			—			—			(359,431		)
Advances to affiliates	(8,978		)	(357,486		)	(93,269		)	—			459,733			—
Other, net	(435		)	—			—			—			—			(435		)
Net cash used in investing activities	(369,356		)	(357,486		)	(124,014		)	(75,760		)	459,733			(466,883		)

Cash flows from financing activities:
Distributions to unitholders	(82,020		)	—			—			—			—			(82,020		)
Borrowings under revolving credit facility	12,000			427,300			—			—			—			439,300
Repayments under revolving credit facility	—			(50,300		)	—			—			—			(50,300		)
Deferred loan costs	—			(2,766		)	—			—			—			(2,766		)
Cash advance from Summit Investments to contributed subsidiaries, net	(12,000		)	—			—			24,214			—			12,214
Expenses paid by Summit Investments on behalf of contributed subsidiaries	3,030			—			—			1,791			—			4,821
Other, net	(912		)	—			—			(4		)	—			(916		)
Advances from affiliates	450,755			—			—			8,978			(459,733		)	—
Net cash provided by financing activities	370,853			374,234			—			34,979			(459,733		)	320,333
Net change in cash and cash equivalents	2,247			(11,769		)	(4,579		)	(949		)	—			(15,050		)
Cash and cash equivalents, beginning of period	73			12,407			6,930			2,383			—			21,793
Cash and cash equivalents, end of period	$	2,320		$	638		$	2,351		$	1,434		$	—		$	6,743

Table of Contents



	Six months ended June 30, 2015
	SMLP			Co-Issuers			Guarantor subsidiaries			Non-guarantor subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	4,476		$	(23,986	)	$	115,962		$	8,544		$	—		$	104,996

Cash flows from investing activities:
Capital expenditures	(393		)	—			(60,562		)	(70,562		)	—			(131,517		)
Contributions to equity method investees	—			—			—			(64,396		)	—			(64,396		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(292,941		)	—			—			—			—			(292,941		)
Advances to affiliates	(1,012		)	(58,425		)	(78,159		)	—			137,596			—
Other, net	—			—			238			—			—			238
Net cash used in investing activities	(294,346		)	(58,425		)	(138,483		)	(134,958		)	137,596			(488,616		)

Cash flows from financing activities:
Distributions to unitholders	(70,619		)	—			—			—			—			(70,619		)
Borrowings under revolving credit facility	135,000			122,000			—			—			—			257,000
Repayments under revolving credit facility	(100,000		)	(51,000		)	—			—			—			(151,000		)
Repayments under term loan	(177,500		)	—			—			—			—			(177,500		)
Deferred loan costs	(50		)	(86		)	—			—			—			(136		)
Proceeds from issuance of common units, net	222,119			—			—			—			—			222,119
Contribution from general partner	4,737			—			—			—			—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	142,500			—			21,719			122,580			—			286,799
Expenses paid by Summit Investments on behalf of contributed subsidiaries	7,354			—			3,447			2,551			—			13,352
Other, net	(936		)	—			—			—			—			(936		)
Advances from affiliates	136,584			—			—			1,012			(137,596		)	—
Net cash provided by financing activities	299,189			70,914			25,166			126,143			(137,596		)	383,816
Net change in cash and cash equivalents	9,319			(11,497		)	2,645			(271		)	—			196
Cash and cash equivalents, beginning of period	7,531			11,621			7,353			1,306			—			27,811
Cash and cash equivalents, end of period	$	16,850		$	124		$	9,998		$	1,035		$	—		$	28,007

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.

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

Table of Contents

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. A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk.

We also earn 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 direct commodity price risk from engaging in any of these additional activities with the exception of crude oil and produced water gathering. We also have indirect exposure to changes in commodity prices in that 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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In thousands)
Selected Financial Results:
Net loss	$	(50,555	)	$	(2,396	)	$	(54,220	)	$	(4,880	)
Net cash provided by operating activities	64,651			57,333			131,500			104,996
EBITDA (1)	(6,068		)	39,171			33,937			77,801
Adjusted EBITDA (1)	72,365			61,918			142,396			123,476
Distributable cash flow (1)	51,024			44,857			102,535			87,617

Acquisitions of gathering systems (2)	$	(569	)	$	290,000		$	866,858		$	292,941
Capital expenditures (3)	30,046			82,047			91,372			131,517
Contributions to equity method investees	—			36,566			15,645			64,396

Distributions to unitholders	$	41,045		$	35,526		$	82,020		$	70,619
Borrowings under revolving credit facility, net	—			43,000			389,000			106,000
Proceeds from issuance of common units, net	—			222,119			—			222,119

_________

(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 and six months ended June 30, 2016. In March 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 second quarter of 2016 increased 0.9% over the per-unit distribution declared in respect of the second quarter of 2015.

Three and six months ended June 30, 2015. In May 2015, we acquired Polar and Divide from subsidiaries of Summit Investments. We funded the drop down with the issuance of common units, borrowings under our revolving credit facility and a general partner contribution.

Table of Contents

Trends and Outlook

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


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


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


•	Capital markets activity and cost of capital;


•	Acquisitions from third parties; and


•	Shifts in operating costs and inflation.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. 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 period since December 31, 2015, except as updated 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 ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness;

Table of Contents


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


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


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

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


•	the financial performance of our assets without regard to (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 make future cash distributions and support our indebtedness; 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.

Table of Contents

Results of Operations

Consolidated Overview of the Three and Six Months Ended June 30, 2016 and 2015

The following table presents certain consolidated and operating data.



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In thousands)
Revenues:
Gathering services and related fees	$	76,187		$	69,754		$	154,287		$	138,194
Natural gas, NGLs and condensate sales	8,581			11,967			16,169			24,580
Other revenues	4,867			5,133			9,750			10,167
Total revenues	89,635			86,854			180,206			172,941
Costs and expenses:
Cost of natural gas and NGLs	6,864			8,574			13,154			18,015
Operation and maintenance	23,410			23,595			49,252			46,385
General and administrative	12,876			11,632			25,755			23,231
Transaction costs	122			822			1,296			932
Depreciation and amortization	27,963			26,019			55,691			51,549
Loss (gain) on asset sales, net	74			(214		)	11			(214		)
Long-lived asset impairment	569			—			569			—
Total costs and expenses	71,878			70,428			145,728			139,898
Other income	19			—			41			1
Interest expense	(16,035		)	(15,599		)	(31,917		)	(30,503		)
Deferred purchase price obligation expense	(17,465		)	—			(24,928		)	—
(Loss) income before income taxes	(15,724		)	827			(22,326		)	2,541
Income tax (expense) benefit	(360		)	263			(283		)	(167		)
Loss from equity method investees	(34,471		)	(3,486		)	(31,611		)	(7,254		)
Net loss	$	(50,555	)	$	(2,396	)	$	(54,220	)	$	(4,880	)

Operating Data:
Aggregate average throughput – gas (MMcf/d)	1,512			1,550			1,518			1,577
Aggregate average throughput rate per Mcf – gas	$	0.45		$	0.42		$	0.45		$	0.42
Average throughput – liquids (Mbbl/d)	86.0			62.9			90.5			58.1
Average throughput rate per Bbl – liquids	$	1.86		$	1.84		$	1.91		$	1.80

Volumes – Gas. Aggregate natural gas throughput volumes decreased during the three and six months ended June 30, 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 during the three and six months ended June 30, 2016 primarily reflecting new pad site connections and producers' drilling activity on the Polar and Divide system. During the the second quarter of 2016, this increase was partially offset by the impact of certain customers shutting in existing production while completion activities occurred. In addition, the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained 2015 volume throughput (see Note 15 to the unaudited condensed consolidated financial statements).

Revenues. Total revenues increased $2.8 million, or 3%, during the three months ended June 30, 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.

Table of Contents


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

Total revenues increased $7.3 million, or 4.2%, during the six months ended June 30, 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.


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

Gathering Services and Related Fees. The increase in gathering services and related fees during the three months ended June 30, 2016 was primarily driven by higher volume throughput on the Polar and Divide system and the development of the Summit Utica and Tioga Midstream systems, partially offset by volume throughput declines at DFW Midstream, Mountaineer Midstream and Grand River.

The aggregate average throughput rate for natural gas increased to $0.45/Mcf during the three months ended June 30, 2016, compared with $0.42/Mcf in the prior-year period, largely due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.86/Bbl during the three months ended June 30, 2016, compared with $1.84/Bbl in the prior-year period primarily as a result of rate redeterminations at Tioga Midstream.

The increase in gathering services and related fees during six months ended June 30, 2016 was primarily driven by higher volume throughput on the Polar and Divide system and the development of the Summit Utica system, partially offset by volume throughput declines at DFW Midstream, Mountaineer Midstream and Grand River.

The aggregate average throughput rate for natural gas increased to $0.45/Mcf during the six months ended June 30, 2016, compared with $0.42/Mcf in the prior-year period, largely due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.91/Bbl during the six months ended June 30, 2016, compared with $1.80/Bbl in the prior-year period primarily as a result of rate redeterminations at Tioga Midstream.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the three months ended June 30, 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.

The decrease in natural gas, NGLs and condensate sales for the six months ended June 30, 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 $1.5 million, or 2%, for the three months ended June 30, 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.


•	an increase in general and administrative expense primarily due to an increase in salaries, benefits and incentive compensation as a result of increased head count and an increase in professional expenses.


•	a decrease in transaction costs, primarily as a result of costs associated with the Polar and Divide Drop Down in the second quarter of 2015.

Total costs and expenses increased $5.8 million, or 4%, for the six months ended June 30, 2016 primarily reflecting:


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


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


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


•	an increase in general and administrative expense primarily due to an increase in salaries, benefits and incentive compensation as a result of increased head count.

Table of Contents

Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs during the three and six months ended June 30, 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 decreased during the three months ended June 30, 2016 reflecting the offsetting effects of declining expenses at Grand River and DFW Midstream and increases due to development of the Summit Utica, Tioga Midstream and Polar and Divide systems. Operation and maintenance expense increased during the six months ended June 30, 2016 primarily reflecting costs associated with repairs to rights-of-way at Mountaineer Midstream and certain environmental remediation expenses at Polar and Divide in addition to overall increases for Summit Utica, Tioga Midstream and Polar and Divide.

General and Administrative. General and administrative expense increased during the three months ended June 30, 2016 reflecting an increase in expenses for salaries, benefits and unit-based compensation and an increase in professional expenses.

General and administrative expense increased during the six months ended June 30, 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.

Transaction Costs. Transaction costs recognized in 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down. Transaction costs recognized in 2015 primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three and six months ended June 30, 2016 was largely driven by an increase in assets placed into service.

Interest Expense. The increase in interest expense during the three and six months ended June 30, 2016 was primarily driven by the higher borrowing costs associated with our revolving credit facility relative to the borrowing costs associated with Summit Investments' debt facilities that had been allocated to the 2016 Drop Down Assets prior to our March 2016 closing of the 2016 Drop Down.

Deferred Purchase Price Obligation Expense. Deferred purchase price obligation expense recognized during the three and six months ended June 30, 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 and Six Months Ended June 30, 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.

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



	Utica Shale (1)
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2016	2015	Percentage Change	2016	2015	Percentage Change
Average throughput (MMcf/d)	167	16	*	150	14	*

__________

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

* Not considered meaningful

Volume throughput for the three and six months ended June 30, 2016 increased due to our continued buildout of the Summit Utica gathering system and our customers’ commissioning of new wells throughout 2015 and into 2016.

Table of Contents

Financial data for our Utica Shale reportable segment follows.



	Utica Shale
	Three months ended June 30,				Percentage Change		Six months ended June 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	5,403	$	515	*		$	9,686	$	904	*
Total revenues	5,403		515		*		9,686		904		*
Costs and expenses:
Operation and maintenance	495		261		90	%	1,020		504		102	%
General and administrative	181		392		(54	)%	750		595		26	%
Depreciation and amortization	952		217		*		1,796		357		*
Total costs and expenses	1,628		870		87	%	3,566		1,456		145	%
Add:
Proportional adjusted EBITDA for equity method investees (1)	12,725		6,552				25,113		11,816
Depreciation and amortization	952		217				1,796		357
Segment adjusted EBITDA	$	17,452	$	6,414	*		$	33,029	$	11,621	*

__________

* Not considered meaningful

(1) Represents our pro rata share of Ohio Gathering's adjusted EBITDA, based on a one-month lag.

Three months ended June 30, 2016. Segment adjusted EBITDA increased $11.0 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 placed into service at Summit Utica.

Six months ended June 30, 2016. Segment adjusted EBITDA increased $21.4 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 placed 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.

Table of Contents

Operating data for our Williston Basin reportable segment follows.



	Williston Basin
	Three months ended June 30,				Percentage Change		Six months ended June 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
Average throughput – natural gas (MMcf/d)	24		23		4	%	24		22		9	%
Average throughput rate per Mcf – natural gas	$	2.63	$	2.17	21	%	$	2.69	$	2.40	12	%
Average throughput – liquids (Mbbl/d)	86.0		62.9		37	%	90.5		58.1		56	%
Average throughput rate per Bbl – liquids	$	1.86	$	1.84	1	%	$	1.91	$	1.80	6	%

Natural gas. Natural gas volume throughput increased during the three and six months ended June 30, 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 during the three and six months ended June 30, 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. In addition, the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained 2015 volume throughput. The increase in 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.

Table of Contents

Financial data for our Williston Basin reportable segment follows.



	Williston Basin
	Three months ended June 30,				Percentage Change		Six months ended June 30,				Percentage Change
	2016		2015 (1)		Percentage Change		2016		2015 (1)		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	19,536	$	14,633	34	%	$	41,951	$	27,484	53	%
Natural gas, NGLs and condensate sales	4,918		5,890		(17	)%	9,196		13,249		(31	)%
Other revenues	3,053		3,127		(2	)%	6,370		5,985		6	%
Total revenues	27,507		23,650		16	%	57,517		46,718		23	%
Costs and expenses:
Cost of natural gas and NGLs	4,980		5,832		(15	)%	9,606		12,968		(26	)%
Operation and maintenance	6,991		6,429		9	%	15,202		12,077		26	%
General and administrative	588		1,598		(63	)%	1,577		3,643		(57	)%
Depreciation and amortization	8,410		7,729		9	%	16,767		15,096		11	%
Loss on asset sales, net	3		—		*		2		—		*
Long-lived asset impairment	569		—		*		569		—		*
Total costs and expenses	21,541		21,588		—	%	43,723		43,784		—	%
Add:
Depreciation and amortization	8,410		7,729				16,767		15,096
Adjustments related to MVC shortfall payments	4,261		2,847				7,797		5,500
Loss on asset sales	6		—				63		—
Long-lived asset impairment	569		—				569		—
Unit-based compensation	—		—				—		85
Less:
Gain on asset sales	3		—				61		—
Segment adjusted EBITDA	$	19,209	$	12,638	52	%	$	38,929	$	23,615	65	%

__________

* Not considered meaningful

(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 June 30, 2016. Segment adjusted EBITDA increased $6.6 million during the three months ended June 30, 2016 reflecting:


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


•	the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines.


•	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.

Table of Contents


•	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.

Depreciation and amortization increased during three months ended June 30, 2016 largely as a result of assets placed into service for the 2016 Drop Down Assets.

Six months ended June 30, 2016. Segment adjusted EBITDA increased $15.3 million during six months ended June 30, 2016 reflecting:


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


•	the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines.


•	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 six months ended June 30, 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. Niobrara G&P 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 June 30,				Percentage Change		Six months ended June 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
Average throughput (MMcf/d)	564		613		(8	)%	568		617		(8	)%
Average throughput rate per Mcf	$	0.50	$	0.45	11	%	$	0.49	$	0.45	9	%

Volume throughput decreased during the three and six months ended June 30, 2016 primarily as a result of the continued suspension of drilling activities by Grand River's anchor customer and the resulting natural declines from existing production. The aggregate average throughput rate increased during 2016 largely as a result of a shift in volume throughput mix.

Table of Contents

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



	Piceance/DJ Basins
	Three months ended June 30,					Percentage Change		Six months ended June 30,					Percentage Change
	2016		2015			Percentage Change		2016		2015			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	25,401	$	24,944		2	%	$	50,792	$	50,509		1	%
Natural gas, NGLs and condensate sales	2,425		4,378			(45	)%	4,627		7,711			(40	)%
Other revenues	1,585		1,761			(10	)%	2,983		3,757			(21	)%
Total revenues	29,411		31,083			(5	)%	58,402		61,977			(6	)%
Costs and expenses:
Cost of natural gas and NGLs	1,884		2,742			(31	)%	3,548		5,047			(30	)%
Operation and maintenance	8,186		9,049			(10	)%	16,782		17,921			(6	)%
General and administrative	566		951			(40	)%	1,999		1,869			7	%
Depreciation and amortization	12,297		11,818			4	%	24,570		23,600			4	%
Loss (gain) on asset sales, net	71		(214		)	*		9		(214		)	*
Total costs and expenses	23,004		24,346			(6	)%	46,908		48,223			(3	)%
Add:
Depreciation and amortization	12,297		11,818					24,570		23,600
Adjustments related to MVC shortfall payments	7,456		9,866					14,973		19,769
Loss on asset sales	71		24					71		24
Add:
Gain on asset sales	—		238					62		238
Segment adjusted EBITDA	$	26,231	$	28,207		(7	)%	$	51,046	$	56,909		(10	)%

__________

* Not considered meaningful

Three months ended June 30, 2016. Segment adjusted EBITDA decreased $2.0 million during the three months ended June 30, 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.

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 services and related fees increased in the second quarter of 2016, offsetting the decline in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 to the consolidated financial statements included in the 2015 Annual Report for additional information).

Six months ended June 30, 2016. Segment adjusted EBITDA decreased $5.9 million during the six months ended June 30, 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 six months ended June 30, 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

Table of Contents

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 half of 2016, offsetting the decline in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 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.

Operating data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Three months ended June 30,				Percentage Change		Six months ended June 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
Average throughput (MMcf/d)	341		356		(4	)%	341		379		(10	)%
Average throughput rate per Mcf	$	0.61	$	0.67	(9	)%	$	0.61	$	0.63	(3	)%

Volume throughput declined during the three and six months ended June 30, 2016 reflecting reduced production due to reduced drilling activity and natural production declines, partially offset by volume throughput growth as a result of the commissioning of an 11-well pad site.

Financial data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Three months ended June 30,						Percentage Change		Six months ended June 30,						Percentage Change
	2016			2015			Percentage Change		2016			2015			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	19,389		$	21,879		(11	)%	$	38,514		$	43,675		(12	)%
Natural gas, NGLs and condensate sales	1,238			1,699			(27	)%	2,346			3,620			(35	)%
Other revenues	229			245			(7	)%	397			425			(7	)%
Total revenues	20,856			23,823			(12	)%	41,257			47,720			(14	)%
Costs and expenses:
Operation and maintenance	6,178			6,336			(2	)%	12,492			13,148			(5	)%
General and administrative	312			381			(18	)%	548			733			(25	)%
Depreciation and amortization	3,928			3,902			1	%	7,847			7,808			—	%
Total costs and expenses	10,418			10,619			(2	)%	20,887			21,689			(4	)%
Add:
Depreciation and amortization	4,057			4,114					8,113			8,271
Adjustments related to MVC shortfall payments	(582		)	(1,778		)			(493		)	(2,001		)
Segment adjusted EBITDA	$	13,913		$	15,540		(10	)%	$	27,990		$	32,301		(13	)%

Three months ended June 30, 2016. Segment adjusted EBITDA decreased $1.6 million during the three months ended June 30, 2016 reflecting:


•	a reduction in gathering services and related fees due to both a lower average gathering rate and reduced volume throughput.


•	the impact of declining natural gas prices and lower volume throughput 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.

Table of Contents


•	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 and lower volume throughput translated into lower electricity expenses.

Six months ended June 30, 2016. Segment adjusted EBITDA decreased $4.3 million during the six months ended June 30, 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 and lower volume throughput 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 and lower volume throughput translated into lower electricity expenses.

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 June 30,		Percentage Change		Six months ended June 30,		Percentage Change
	2016	2015	Percentage Change		2016	2015	Percentage Change
Average throughput (MMcf/d)	416	542	(23	)%	435	545	(20	)%

__________

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

Volume throughput declined during the three and six months ended June 30, 2016 due to our anchor customer’s decision to defer completion activities in 2015 and not offset natural production declines. Volume throughput during 2016 was also impacted by repairs on a third-party NGL pipeline located downstream of the Sherwood Processing Complex in June 2016 limiting the amount of natural gas we could deliver for a period time during the quarter. The repairs to the third-party NGL pipeline were completed in early July 2016 and volume throughput on the Mountaineer system resumed flowing at levels commensurate with levels we experienced prior to the incident.

Financial data for our Marcellus Shale reportable segment follows.



	Marcellus Shale
	Three months ended June 30,				Percentage Change		Six months ended June 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,458	$	7,783	(17	)%	$	13,344	$	15,622	(15	)%
Total revenues	6,458		7,783		(17	)%	13,344		15,622		(15	)%
Costs and expenses:
Operation and maintenance	1,560		1,520		3	%	3,756		2,735		37	%
General and administrative	91		101		(10	)%	180		191		(6	)%
Depreciation and amortization	2,222		2,169		2	%	4,441		4,338		2	%
Total costs and expenses	3,873		3,790		2	%	8,377		7,264		15	%
Add:
Depreciation and amortization	2,222		2,169				4,441		4,338
Segment adjusted EBITDA	$	4,807	$	6,162	(22	)%	$	9,408	$	12,696	(26	)%

Table of Contents

Three months ended June 30, 2016. Segment adjusted EBITDA decreased $1.4 million during the three months ended June 30, 2016 reflecting:


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

Six months ended June 30, 2016. Segment adjusted EBITDA decreased $3.3 million during the six months ended June 30, 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.

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 June 30,		Percentage Change		Six months ended June 30,		Percentage Change
	2016	2015	Percentage Change		2016	2015	Percentage Change
	(In thousands)
Costs and expenses:
General and administrative	11,138	8,209	36	%	20,701	16,200	28	%
Transaction costs	122	822	(85	)%	1,296	932	39	%
Interest expense (1)	16,035	15,599	3	%	31,917	30,503	5	%
Deferred purchase price obligation expense	17,465	—	*		24,928	—	*

__________

* 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 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 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 period from January 1, 2015 to May 18, 2015 for Polar and Divide and for the period from March 3, 2016 to June 30, 2016 for the Contributed Entities.

Interest Expense. The increase in interest expense during the six months ended June 30, 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).

Table of Contents

Non-GAAP Financial Measures

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


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


•	Adjusted EBITDA. We define adjusted EBITDA as EBITDA plus our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, deferred purchase price obligation expense, 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 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.

Table of Contents


•	Proportional adjusted EBITDA for equity method investees accounts for our pro rata share of Ohio Gathering's adjusted EBITDA, based on a one-month lag.

•

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 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 and distributable cash flow include transaction costs. These unusual expenses are settled in cash. For additional information, see "Results of Operations—Corporate" herein.

Table of Contents

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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In thousands)
Reconciliation of net loss to EBITDA, adjusted EBITDA and distributable cash flow:
Net loss	$	(50,555	)	$	(2,396	)	$	(54,220	)	$	(4,880	)
Add:
Interest expense	16,035			15,599			31,917			30,503
Income tax expense	360			—			283			167
Depreciation and amortization	28,092			26,231			55,957			52,012
Less:
Interest income	—			—			—			1
Income tax benefit	—			263			—			—
EBITDA	$	(6,068	)	$	39,171		$	33,937		$	77,801
Add:
Proportional adjusted EBITDA for equity method investees	12,725			6,552			25,113			11,816
Adjustments related to MVC shortfall payments	11,135			10,935			22,277			23,268
Unit-based and noncash compensation	1,994			1,988			3,950			3,551
Deferred purchase price obligation expense	17,465			—			24,928			—
Loss on asset sales	77			24			134			24
Long-lived asset impairment	569			—			569			—
Less:
Loss from equity method investees	(34,471		)	(3,486		)	(31,611		)	(7,254		)
Gain on asset sales	3			238			123			238
Adjusted EBITDA	$	72,365		$	61,918		$	142,396		$	123,476
Add:
Cash interest received	—			—			—			1
Cash taxes received	—			—			50			—
Less:
Cash interest paid	6,300			4,867			31,464			30,331
Senior notes interest adjustment	9,750			9,750			—			(1,421		)
Maintenance capital expenditures	5,291			2,444			8,447			6,950
Distributable cash flow	$	51,024		$	44,857		$	102,535		$	87,617

Table of Contents

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.



	Six months ended June 30,
	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	$	131,500		$	104,996
Add:
Loss from equity method investees	(31,611		)	(7,254		)
Interest expense, excluding deferred loan costs	29,970			28,307
Income tax expense	283			167
Changes in operating assets and liabilities	(42,566		)	(30,481		)
Gain on asset sales	123			238
Less:
Unit-based and noncash compensation	3,950			3,551
Distributions from equity method investees	24,181			13,869
Deferred purchase price obligation expense	24,928			—
Interest income	—			1
Loss on asset sales	134			24
Long-lived asset impairment	569			—
Write-off of debt issuance costs	—			727
EBITDA	$	33,937		$	77,801
Add:
Proportional adjusted EBITDA for equity method investees	25,113			11,816
Adjustments related to MVC shortfall payments	22,277			23,268
Unit-based and noncash compensation	3,950			3,551
Deferred purchase price obligation expense	24,928			—
Loss on asset sales	134			24
Long-lived asset impairment	569			—
Less:
Loss from equity method investees	(31,611		)	(7,254		)
Gain on asset sales	123			238
Adjusted EBITDA	$	142,396		$	123,476
Add:
Cash interest received	—			1
Cash taxes received	50			—
Less:
Cash interest paid	31,464			30,331
Senior notes interest adjustment	—			(1,421		)
Maintenance capital expenditures	8,447			6,950
Distributable cash flow	$	102,535		$	87,617

Table of Contents

Liquidity and Capital Resources

Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt instruments.

Capital Markets Activity

We had no capital markets activity during the six months ended June 30, 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. As of June 30, 2016, the outstanding balance of the revolving credit facility was $721.0 million and the unused portion totaled $529.0 million. There were no defaults or events of default during 2016 and, as of June 30, 2016, we were in compliance with the covenants in the revolving credit facility.

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

For additional information on our revolving credit facility and the Senior Notes, see Notes 9 and 17 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:



	Six months ended June 30,
	2016			2015
	(In thousands)
Net cash provided by operating activities	$	131,500		$	104,996
Net cash used in investing activities	(466,883		)	(488,616		)
Net cash provided by financing activities	320,333			383,816
Net change in cash and cash equivalents	$	(15,050	)	$	196

Operating activities. Cash flows from operating activities increased by $26.5 million from 2015 to 2016 primarily due to the impact of cash payments in 2015 associated with environmental remediation costs for Meadowlark Midstream. Also contributing to the increase in operating cash flows was a $10.3 million increase in distributions from Ohio Gathering.

Investing activities. Cash flows used in investing activities in 2016 were related primarily to our acquisition and ongoing expansion of the 2016 Drop Down Assets.

Cash flows used in investing activities in 2015 were related primarily to (i) the Polar and Divide Drop Down and 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. Net cash provided by financing activities in 2016 primarily reflects:


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

Table of Contents


•	distributions declared and paid in 2016.

Net cash provided by financing activities in 2015 primarily reflects:


•	cash advances from Summit Investments;


•	proceeds from the issuance of common units;


•	net repayments under our revolving credit facility; and


•	distributions declared and paid in 2015.

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 $864.5 million based on information available as of June 30, 2016. There are no cash interest payments associated with the deferred purchase price obligation.

Capital Requirements

Cash paid for capital expenditures by reportable segment and in total follows.



	Six months ended June 30,
	2016		2015
	(In thousands)
Capital expenditures:
Utica Shale	$	54,064	$	40,195
Williston Basin	21,919		76,470
Piceance/DJ Basins	10,633		11,900
Barnett Shale	2,109		1,922
Marcellus Shale	2,135		637
Total reportable segment capital expenditures	90,860		131,124
Corporate	512		393
Total capital expenditures	$	91,372	$	131,517

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 six months ended June 30, 2016, SMLP recorded total capital expenditures of $91.4 million, which included $8.4 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 June 30, 2016, together with financial support from our Sponsor and/or access to the debt and equity capital

Table of Contents

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.

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 six months ended June 30, 2016 follow.



	Williston Basin		Piceance/DJ Basins		Barnett Shale			Total
	(In thousands)
Adjustments related to MVC shortfall payments:
Net change in deferred revenue for MVC shortfall payments (1)	$	235	$	2,475	$	(677	)	$	2,033
Expected MVC shortfall payments (2)	7,562		12,498		184			20,244
Total adjustments related to MVC shortfall payments	$	7,797	$	14,973	$	(493	)	$	22,277

__________

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

(2) As of June 30, 2016, accounts receivable included $4.5 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 six months ended June 30, 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

Table of Contents

management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results.

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 six months ended June 30, 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 March 3, 2016 and December 31, 2019 and (ii) Business Adjusted EBITDA, an income-based measure as defined in the Contribution Agreement, during the period from March 3, 2016 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 various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.

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


•	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;

Table of Contents


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


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

•

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


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


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


•	the ability to attract and retain key management personnel;


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


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


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


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


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


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


•	weather conditions and seasonal trends;


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


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


•	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 June 30, 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

Table of Contents

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 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.

We maintain disclosure controls and procedures, as defined by Rule 13a-15 under the Exchange Act of 1934, that are designed to provide reasonable assurance that information that is required to be timely disclosed is accumulated and communicated to management in a manner that allows for such timely disclosure. In designing and evaluating such controls and procedures, we recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Our management is necessarily required to use judgment in evaluating controls and procedures.

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report was performed, with the participation of our Chief Executive Officer and Chief Financial Officer. This evaluation is performed to determine if our disclosure controls and procedures are effective to provide reasonable assurance that (1) information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and (2) such information is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms.

Subsequent to June 30, 2016, we identified a material weakness in our internal control over financial reporting relating to disclosure required in a footnote to our financial statements under Rule 3-10 of Regulation S-X ("Rule 3-10"). Based upon that discovery, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective at a level that provides reasonable assurance as of the end of the period covered by this report.

We designed our control over the evaluation of reporting responsibilities under Rule 3-10 to operate each time there is a change to our guarantor structure. The material weakness in internal control over financial reporting resulted in our failure to identify additional reporting requirements resulting from a change in the guarantor structure of the Senior Notes as a result of the 2016 Drop Down. As a result of this failure, we did not incorporate additional required disclosures into our Form 10-Q for the period ending March 31, 2016. The omission was identified during a subsequent review of the guarantor structure of the Senior Notes and we have incorporated the required disclosures into our current report on Form 10-Q for the period ending June 30, 2016.

Subsequent to June 30, 2016, we took steps to implement additional measures to remediate the underlying causes, primarily through enhancements to our documented procedures for review and evaluation of our reporting requirements under Rule 3-10.

Except as noted above, there have been no changes in the Company's internal control over financial reporting as of June 30, 2016, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Table of Contents

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 in the 2015 Annual Report and in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2016 as filed with the SEC on May 9, 2016, both of which are incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of (i) the 2015 Annual Report and (ii) the quarterly report on Form 10-Q for the quarterly period ended March 31, 2016 as filed with the SEC on May 9, 2016 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.

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 June 30, 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 quarter ended June 30, 2016.



Period	(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)
April 1 - 30, 2016	516,431	$	17.77	516,431	$	10,060,517
May 1 - 31, 2016	298,598	20.72		298,598	3,874,913
June 1 - 30, 2016	96,684	20.95		96,684	1,849,723
Total	911,713	$	19.07	911,713	$	1,849,723

__________

(1) In December 2015, Energy Capital Partners approved a unit purchase program of up to $100.0 million of SMLP common units (the "Purchase Program"). See the 2015 Annual Report for additional information on our Sponsor and the Purchase Program.

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))
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 June 30, 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.

Table of Contents

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)

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

Exhibit

EXHIBIT 31.1

CERTIFICATIONS

I, Steven J. Newby, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Summit Midstream Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	August 9, 2016	/s/ Steven J. Newby
		Steven J. Newby
		President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)

Ex 31.1-1

Exhibit

EXHIBIT 31.2

CERTIFICATIONS

I, Matthew S. Harrison, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Summit Midstream Partners, LP;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	August 9, 2016	/s/ Matthew S. Harrison
		Matthew S. Harrison
		Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)

Ex 31.2-1

Exhibit

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Summit Midstream Partners, LP (the “Registrant”) for the quarterly period ended June 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Steven J. Newby, as President, Chief Executive Officer and Director of Summit Midstream GP, LLC, the general partner of the Registrant, and Matthew S. Harrison, as Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC, the general partner of the Registrant, each hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:



(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.




		/s/ Steven J. Newby
Name:		Steven J. Newby
Title:		President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)
Date:		August 9, 2016


		/s/ Matthew S. Harrison
Name:		Matthew S. Harrison
Title:		Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)
Date:		August 9, 2016

Ex 32.1-1