Summit Midstream Partners, LP - Quarter Report: 2016 September (Form 10-Q)

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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 September 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 October 31, 2016
Common Units		72,088,168 units
General Partner Units		1,471,187 units

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PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	1
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015	2
	Unaudited Condensed Consolidated Statements of Partners' Capital for the nine months ended September 30, 2016 and 2015	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 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.	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	59
Item 4.	Controls and Procedures.	60

PART II	OTHER INFORMATION	61
Item 1.	Legal Proceedings.	61
Item 1A.	Risk Factors.	61
Item 6.	Exhibits.	61

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Glossary of Terms

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

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

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

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

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

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

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

segment adjusted EBITDA: calculated as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) impairments and (vi) other noncash expenses or losses, less other noncash income or gains.

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

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

Tcf: one trillion cubic feet

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

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

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

iii

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,		December 31,
	2016		2015
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	7,597	$	21,793
Accounts receivable	52,448		89,581
Other current assets	4,766		3,573
Total current assets	64,811		114,947
Property, plant and equipment, net	1,853,058		1,812,783
Intangible assets, net	431,713		461,310
Investment in equity method investees	705,845		751,168
Goodwill	16,211		16,211
Other noncurrent assets	8,439		8,253
Total assets	$	3,080,077	$	3,164,672

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	13,110	$	40,808
Due to affiliate	114		1,149
Deferred revenue	—		677
Ad valorem taxes payable	9,413		10,271
Accrued interest	7,733		17,483
Accrued environmental remediation	7,954		7,900
Other current liabilities	19,075		13,297
Total current liabilities	57,399		91,585
Long-term debt	1,224,919		1,267,270
Deferred Purchase Price Obligation	538,543		—
Deferred revenue	49,042		45,486
Noncurrent accrued environmental remediation	3,082		5,764
Other noncurrent liabilities	7,692		7,268
Total liabilities	1,880,677		1,417,373
Commitments and contingencies (Note 15)

Common limited partner capital (72,088 units issued and outstanding at September 30, 2016 and 42,063 units issued and outstanding at December 31, 2015)	1,158,343		744,977
Subordinated limited partner capital (0 units issued and outstanding at September 30, 2016 and 24,410 units issued and outstanding at December 31, 2015)	—		213,631
General partner interests (1,471 units issued and outstanding at September 30, 2016 and 1,355 units issued and outstanding at December 31, 2015)	29,904		25,634
Noncontrolling interest	11,153		—
Summit Investments' equity in contributed subsidiaries	—		763,057
Total partners' capital	1,199,400		1,747,299
Total liabilities and partners' capital	$	3,080,077	$	3,164,672

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	80,296		$	101,574		$	234,583		$	239,768
Natural gas, NGLs and condensate sales	9,578			8,710			25,747			33,290
Other revenues	5,199			4,917			14,949			15,084
Total revenues	95,073			115,201			275,279			288,142
Costs and expenses:
Cost of natural gas and NGLs	6,986			6,959			20,140			24,974
Operation and maintenance	23,059			24,660			72,311			71,044
General and administrative	12,368			10,829			38,123			34,060
Transaction costs	—			322			1,296			1,254
Depreciation and amortization	27,979			26,396			83,670			77,945
Environmental remediation	—			20,000			—			20,000
Loss (gain) on asset sales, net	13			—			24			(214		)
Long-lived asset impairment	1,172			7,696			1,741			7,696
Total costs and expenses	71,577			96,862			217,305			236,759
Other income	51			1			92			2
Interest expense	(15,733		)	(14,360		)	(47,650		)	(44,863		)
Deferred Purchase Price Obligation expense	(6,188		)	—			(31,116		)	—
Income (loss) before income taxes and income (loss) from equity method investees	1,626			3,980			(20,700		)	6,522
Income tax benefit (expense)	142			(199		)	(141		)	(366		)
Income (loss) from equity method investees	270			(240		)	(31,341		)	(7,494		)
Net income (loss)	$	2,038		$	3,541		$	(52,182	)	$	(1,338	)
Less:
Net (loss) income attributable to Summit Investments	—			(20,063		)	2,745			(29,594		)
Net income (loss) attributable to noncontrolling interest	116			—			(108		)	—
Net income (loss) attributable to SMLP	1,922			23,604			(54,819		)	28,256
Less net income (loss) attributable to general partner, including IDRs	2,137			2,408			4,883			5,866
Net (loss) income attributable to limited partners	$	(215	)	$	21,196		$	(59,702	)	$	22,390

(Loss) earnings per limited partner unit:
Common unit – basic	$	0.00		$	0.32		$	(0.89	)	$	0.33
Common unit – diluted	$	0.00		$	0.32		$	(0.89	)	$	0.33
Subordinated unit – basic and diluted				$	0.32					$	0.40

Weighted-average limited partner units outstanding:
Common units – basic	67,844			41,974			66,978			38,258
Common units – diluted	67,844			42,147			66,978			38,387
Subordinated units – basic and diluted				24,410						24,410

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL



	Partners' capital									Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated			General partner						Total
	(In thousands)
Partners' capital, January 1, 2015	$	649,060		$	293,153		$	24,676		$	863,789		$	1,830,678
Net income (loss)	14,129			8,261			5,866			(29,594		)	(1,338		)
Distributions to unitholders	(62,694		)	(41,376		)	(7,029		)	—			(111,099		)
Unit-based compensation	4,954			—			—			—			4,954
Tax withholdings on vested SMLP LTIP awards	(1,435		)	—			—			—			(1,435		)
Issuance of common units, net of offering costs	222,014			—			—			—			222,014
Contribution from general partner	—			—			4,737			—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			292,406			292,406
Purchase of Polar and Divide	—			—			—			(285,677		)	(285,677		)
Excess of acquired carrying value over consideration paid for Polar and Divide	80,079			47,681			2,607			(130,367		)	—
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			16,639			16,639
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			822			822
Class B membership interest noncash compensation	—			—			—			641			641
Partners' capital, September 30, 2015	$	906,107		$	307,719		$	30,857		$	728,659		$	1,973,342

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)



	Partners' capital									Noncontrolling interest			Summit Investments' equity in contributed subsidiaries
	Limited partners						General partner
	Common			Subordinated			General partner									Total
	(In thousands)
Partners' capital, January 1, 2016	$	744,977		$	213,631		$	25,634		$	—		$	763,057		$	1,747,299
Net (loss) income	(60,742		)	1,040			4,883			(108		)	2,745			(52,182		)
Distributions to unitholders	(100,762		)	(14,034		)	(8,268		)	—			—			(123,064		)
Unit-based compensation	5,625			—			—			—			—			5,625
Tax withholdings on vested SMLP LTIP awards	(796		)	—			—			—			—			(796		)
Issuance of common units, net of offering costs	126,115			—			—			—			—			126,115
Contribution from general partner	—			—			2,702			—			—			2,702
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	245			—			—			—			130			375
Partners' capital, September 30, 2016	$	1,158,343		$	—		$	29,904		$	11,153		$	—		$	1,199,400

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine months ended September 30,
	2016			2015
	(In thousands)
Cash flows from operating activities:
Net loss	$	(52,182	)	$	(1,338	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	84,058			78,593
Amortization of deferred loan costs	3,027			3,240
Deferred Purchase Price Obligation expense	31,116			—
Unit-based and noncash compensation	6,000			5,595
Loss from equity method investees	31,341			7,494
Distributions from equity method investees	34,139			23,435
Loss (gain) on asset sales, net	24			(214		)
Long-lived asset impairment	1,741			7,696
Write-off of debt issuance costs	—			727
Changes in operating assets and liabilities:
Accounts receivable	37,133			56,951
Trade accounts payable	(1,795		)	(2,400		)
Due to affiliate	(1,035		)	853
Change in deferred revenue	2,879			(24,606		)
Ad valorem taxes payable	(858		)	(1,578		)
Accrued interest	(9,750		)	(11,125		)
Accrued environmental remediation	(2,628		)	(3,314		)
Other, net	5,495			(1,912		)
Net cash provided by operating activities	168,705			138,097
Cash flows from investing activities:
Capital expenditures	(122,735		)	(205,429		)
Contributions to equity method investees	(20,157		)	(74,375		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(359,431		)	(288,618		)
Other, net	(373		)	238
Net cash used in investing activities	(502,696		)	(568,184		)

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)



	Nine months ended September 30,
	2016			2015
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(123,064		)	(111,099		)
Borrowings under revolving credit facility	490,300			317,000
Repayments under revolving credit facility	(189,300		)	(151,000		)
Repayments under term loan	—			(180,000		)
Deferred loan costs	(3,013		)	(204		)
Proceeds from issuance of common units, net	126,115			222,014
Contribution from general partner	2,702			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	12,214			292,406
Expenses paid by Summit Investments on behalf of contributed subsidiaries	4,821			16,639
Other, net	(980		)	(1,566		)
Net cash provided by financing activities	319,795			408,927
Net change in cash and cash equivalents	(14,196		)	(21,160		)
Cash and cash equivalents, beginning of period	21,793			27,811
Cash and cash equivalents, end of period	$	7,597		$	6,651

Supplemental cash flow disclosures:
Cash interest paid	$	57,217		$	54,303
Less capitalized interest	3,133			2,281
Interest paid (net of capitalized interest)	$	54,084		$	52,022

Cash paid for taxes	$	—		$	—

Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	9,076		$	39,601
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			822
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	—			130,367
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.

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, was formed in May 2012 and began operations in October 2012 in connection with its initial public offering ("IPO") of common units representing limited partner interests. 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 approximate 2% general partner interest in SMLP and SMLP's incentive distribution rights ("IDRs"), Summit Investments has indirect ownership interests in our common units. As of September 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% 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, a subsidiary of Summit Investments retained a 1% 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;

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•	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 September 30, 2016, the unaudited condensed consolidated statements of operations for the three- and nine-month periods ended September 30, 2016 and 2015, and the unaudited condensed consolidated statements of partners' capital and cash flows for the nine-month periods ended September 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 and by our current report on Form 8-K/A dated September 1, 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 our current presentation. We evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts

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



	Three months ended September 30, 2015		Nine months ended September 30, 2015
	(In thousands)
Gathering services and related fees	$	2,795	$	9,263
Other revenues	513		1,771
Net impact on total revenues	$	3,308	$	11,034

Cost of natural gas and NGLs	$	3,308	$	11,034
Net impact on total costs and expenses	$	3,308	$	11,034

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.

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

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

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

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 approximate 2% interest in net income or loss and (iv) any payment of IDRs, by the weighted-average number of limited partner units outstanding. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.

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

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

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

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

Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with debt incurred by Summit Investments or a subsidiary thereof, which was allocated to but not ultimately assumed by the Partnership and later replaced with bank borrowings or debt capital at the Partnership, we allocate a portion of that debt, net of 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"). Under ASU 2014-09, revenue will be recognized under a five-step model: (i) identify the contract with the customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to performance obligations; and (v) recognize revenue when (or as) the performance obligation is satisfied. In its original form, ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016; early adoption was not permitted. In July 2015, the FASB reaffirmed the guidance in its April 2015 proposed ASU that defers for one year the effective date of the ASU 2014-09 for both public and nonpublic entities reporting under U.S. GAAP and allows early adoption as of the original effective date. We expect to adopt the provisions of ASU 2014-09 effective January 1, 2018. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.

•

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. We are currently evaluating the impact of this guidance on lessor accounting but have made no determinations at this time. ASU 2016-02 is effective for public companies for fiscal years beginning after December 15, 2018, and requires the modified retrospective approach for transition. We are currently evaluating the provisions of ASU 2016-02 to determine its impact on our financial statements and related disclosures and expect to adopt its provisions effective January 1, 2019.

•

ASU No. 2016-08 Revenue From Contracts With Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) ("ASU 2016-08"). ASU 2016-08 does not change the core principle of Topic 606, rather it clarifies the implementation guidance on principal versus agent considerations. We expect to adopt the provisions of ASU 2016-08 effective January 1, 2018. Our position regarding the impact of and transition method for this update is the same as for ASU 2014-09.

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•

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. As a partnership that is generally not subject to taxes, the primary impact of adopting ASU 2016-09 will be to change our classification of certain share-based payment awards activity in the statement of cash flows.

•

ASU No. 2016-10 Revenue From Contracts With Customers (Topic 606): Identifying Performance Obligations and Licensing ("ASU 2016-10"). ASU 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. We expect to adopt the provisions of ASU 2016-10 effective January 1, 2018. Our position regarding the impact of and transition method for this update is the same as for ASU 2014-09.

•

ASU No. 2016-12 Revenue From Contracts With Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ("ASU 2016-12"). ASU 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 completed contracts at transition. We expect to adopt the provisions of ASU 2016-12 effective January 1, 2018. Our position regarding the impact of and transition method for this update is the same as for ASU 2014-09.

•

ASU No. 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) ("ASU 2016-15"). ASU 2016-15 addresses how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The applicable provisions relate to distributions received from equity method investees. ASU 2016-15 prescribes a method for differentiating between returns of investment (which should be classified as inflows from investing activities) and returns on investment (which should be classified as inflows from operating activities). With respect to distributions from equity method investees, entities make this determination by applying a cumulative-earnings approach or a nature of the distribution approach. The ASU formalizes each of these methods and allows an entity to choose either one as an accounting policy election. ASU 2016-15 is effective for public business entities for fiscal years beginning after December 15, 2017. Early adoption is permitted. The amendments in ASU 2016-15 are to be applied using a retrospective transition method to each period presented. We are currently evaluating the provisions of ASU 2016-15 to determine (i) whether we will elect the cumulative-earnings approach or the nature of the distribution approach and (ii) the impact on our financial statements and related disclosures.

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 September 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.

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As noted above, the Utica Shale reportable segment includes our investment in Ohio Gathering (see Note 7). 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.



	September 30, 2016		December 31, 2015
	(In thousands)
Assets:
Utica Shale (1)	$	903,345	$	886,224
Williston Basin	715,789		740,361
Piceance/DJ Basins	816,776		866,095
Barnett Shale	401,424		416,586
Marcellus Shale	226,748		233,116
Total reportable segment assets	3,064,082		3,142,382
Corporate	15,995		22,290
Total assets	$	3,080,077	$	3,164,672

__________

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

Revenues by reportable segment follow.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
Revenues:
Utica Shale	$	7,665	$	1,354	$	17,351	$	2,258
Williston Basin	30,194		23,353		87,710		70,071
Piceance/DJ Basins	31,076		63,743		89,479		125,720
Barnett Shale	19,490		19,788		60,747		67,508
Marcellus Shale	6,648		6,963		19,992		22,585
Total reportable segment revenues and total revenues	$	95,073	$	115,201	$	275,279	$	288,142

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



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016	2015
Percentage of total revenues:
Counterparty A - Piceance/DJ Basins	10	%	*		*	*
Counterparty B - Piceance/DJ Basins	*		34	%	*	17	%
Counterparty C - Piceance/DJ Basins	*		*		*	11	%

__________

* Less than 10%

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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 September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
Depreciation and amortization:
Utica Shale	$	961	$	335	$	2,756	$	691
Williston Basin	8,446		8,003		25,214		23,100
Piceance/DJ Basins	12,273		11,854		36,843		35,454
Barnett Shale	4,043		4,081		12,155		12,352
Marcellus Shale	2,224		2,170		6,665		6,508
Total reportable segment depreciation and amortization	27,947		26,443		83,633		78,105
Corporate	154		138		425		488
Total depreciation and amortization	$	28,101	$	26,581	$	84,058	$	78,593

Cash paid for capital expenditures by reportable segment follow.



	Nine months ended September 30,
	2016		2015
	(In thousands)
Capital expenditures:
Utica Shale	$	72,036	$	71,423
Williston Basin	30,687		110,720
Piceance/DJ Basins	15,421		16,712
Barnett Shale	2,716		4,909
Marcellus Shale	971		1,238
Total reportable segment capital expenditures	121,831		205,002
Corporate	904		427
Total capital expenditures	$	122,735	$	205,429

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 (i) total revenues less total expenses, excluding impairments and other noncash income or expense items and (ii) amortization for deferred contract costs; multiplied by our ownership interest in Ohio Gathering during the respective period.

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

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Segment adjusted EBITDA by reportable segment follows.



	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016		2015
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	17,042	$	11,031		$	50,071	$	22,651
Williston Basin	21,815		(5,800		)	60,745		17,817
Piceance/DJ Basins	28,074		26,162			79,120		83,070
Barnett Shale	13,128		13,143			41,118		45,444
Marcellus Shale	5,146		5,795			14,554		18,492
Total of reportable segments’ measures of profit or loss	$	85,205	$	50,331		$	245,608	$	187,474

__________

(1) Includes our proportional share of adjusted EBITDA for Ohio Gathering, based on a one-month lag.

A reconciliation of income or loss before income taxes to total of reportable segments' measures of profit or loss follows.



	Three months ended September 30,					Nine months ended September 30,
	2016		2015			2016			2015
	(In thousands)
Reconciliation of income (loss) before income taxes and income (loss) from equity method investees to total of reportable segments' measures of profit or loss:
Income (loss) before income taxes and income (loss) from equity method investees	$	1,626	$	3,980		$	(20,700	)	$	6,522
Add:
Corporate expenses (1)	8,722		6,848			26,728			20,515
Interest expense	15,733		14,360			47,650			44,863
Deferred Purchase Price Obligation expense	6,188		—			31,116			—
Depreciation and amortization	28,101		26,581			84,058			78,593
Proportional adjusted EBITDA for equity method investees	10,059		10,177			35,173			21,992
Adjustments related to MVC shortfall payments	11,541		(21,354		)	33,818			1,914
Unit-based and noncash compensation	2,050		2,044			6,000			5,595
Loss on asset sales	34		—			168			24
Long-lived asset impairment	1,172		7,696			1,741			7,696
Less:
Interest income	—		1			—			2
Gain on asset sales	21		—			144			238
Total of reportable segments’ measures of profit or loss	$	85,205	$	50,331		$	245,608		$	187,474

__________

(1) Corporate expenses 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 and transaction costs, for the purpose of evaluating their performance.

We include adjustments related to MVC shortfall payments in our calculation of segment adjusted EBITDA to account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. With respect to the impact of a net change in deferred revenue for MVC shortfall payments, we treat increases in deferred revenue balances as a favorable adjustment to segment adjusted EBITDA, while decreases in deferred revenue balances are treated as an unfavorable adjustment to

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segment adjusted EBITDA. We also include a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. The expected MVC shortfall payment adjustments have not been billed to our customers and are not recognized in our unaudited condensed consolidated financial statements.

Adjustments related to MVC shortfall payments by reportable segment follow.



	Three months ended September 30, 2016
	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	$	—	$	847	$	—	$	847
Expected MVC shortfall payments	4,195		6,412		87		10,694
Total adjustments related to MVC shortfall payments	$	4,195	$	7,259	$	87	$	11,541



	Three months ended September 30, 2015
	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	$	—	$	(30,451	)	$	—	$	(30,451	)
Expected MVC shortfall payments	3,470		5,541			86		9,097
Total adjustments related to MVC shortfall payments	$	3,470	$	(24,910	)	$	86	$	(21,354	)



	Nine months ended September 30, 2016
	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	$	235	$	3,321	$	(677	)	$	2,879
Expected MVC shortfall payments	11,757		18,911		271			30,939
Total adjustments related to MVC shortfall payments	$	11,992	$	22,232	$	(406	)	$	33,818



	Nine months ended September 30, 2015
	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	$	(27	)	$	(22,879	)	$	(1,700	)	$	(24,606	)
Expected MVC shortfall payments	8,997			17,738			(215		)	26,520
Total adjustments related to MVC shortfall payments	$	8,970		$	(5,141	)	$	(1,915	)	$	1,914

4. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.



	September 30, 2016		December 31, 2015
	(In thousands)
Gathering and processing systems and related equipment	$	2,000,401	$	1,883,139
Construction in progress	48,772		75,132
Land and line fill	11,442		11,055
Other	33,596		32,427
Total	2,094,211		2,001,753
Less accumulated depreciation	241,153		188,970
Property, plant and equipment, net	$	1,853,058	$	1,812,783

Depreciation expense and capitalized interest follow.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
Depreciation expense	$	17,609	$	16,082	$	52,574	$	47,067
Capitalized interest	1,354		920		3,133		2,281

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.



	September 30, 2016
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(10,478	)	$	13,717
Contract intangibles	12.5	426,464		(137,614		)	288,850
Rights-of-way	26.1	152,586		(23,440		)	129,146
Total intangible assets		$	603,245	$	(171,532	)	$	431,713

Unfavorable gas gathering contract	10.0	$	10,962	$	(6,633	)	$	4,329



	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

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We recognized amortization expense in other revenues as follows:



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(289	)	$	(351	)	$	(944	)	$	(1,152	)
Amortization expense – unfavorable gas gathering contract	167			166			556			504

We recognized amortization expense in costs and expenses as follows:



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
Amortization expense – contract intangibles	$	8,854	$	8,835	$	26,562	$	26,505
Amortization expense – rights-of-way	1,517		1,479		4,534		4,373

The estimated aggregate 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	$	10,810	$	264
2017	42,041		1,047
2018	41,495		1,035
2019	41,740		1,045
2020	44,388		938

6. GOODWILL

We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. We test goodwill for impairment using a two-step quantitative test. In the first step, we compare the fair value of the reporting unit to its carrying value, including goodwill. If the reporting unit’s fair value exceeds its carrying value, including goodwill, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value, including goodwill, exceeds its fair value, we proceed to step two. In step two, we compare the carrying value of the reporting unit, including goodwill, to its implied fair value. If we determine that the carrying value of a reporting unit, including goodwill, exceeds its implied fair value, we recognize the excess of the carrying value over the implied fair value as a goodwill impairment loss.

We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2016 using a combination of the income and market approaches. We determined that its fair value substantially exceeded its carrying value, including goodwill; as such, there 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-

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recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

7. EQUITY METHOD INVESTMENTS

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

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

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

Summit Investments accounted for its initial ownership interests in Ohio Gathering under the cost method due to its ownership percentage and because it determined that it was not the primary beneficiary. Subsequent to the Option Exercise, Summit Investments accounted for its ownership interests in Ohio Gathering as an equity method investment 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% ownership interest through the 2016 Drop Down, at which point SMLP began making contributions and receiving distributions such that it maintained its 40% ownership interest through September 30, 2016.

In June 2016, an impairment loss was recognized by OCC. Although we recognize activity for Ohio Gathering on a one-month lag, we recorded the impairment loss in our results of operations for the second quarter of 2016 because the information was available to us. We recorded our 40% share of the impairment loss, or $37.8 million, in income (loss) from equity method investees in the unaudited condensed consolidated statements of operations.

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



Investment in equity method investees, September 30, 2016	$	705,845
September cash contributions	(2,180		)
September cash distributions	3,512
Basis difference	(146,875		)
Investment in equity method investees, net of basis difference, August 31, 2016	$	560,302

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



	Three months ended August 31, 2016					Three months ended August 31, 2015
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	34,018	$	3,478		$	33,271	$	4,174
Total operating expenses	24,189		5,092			24,669		4,672
Net income (loss)	9,825		(806		)	8,403		(659		)



	Nine months ended August 31, 2016					Nine months ended August 31, 2015
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	110,261	$	14,093		$	83,453	$	5,034
Total operating expenses	69,294		108,399			70,996		10,738
Net income (loss)	40,962		(94,051		)	12,259		(6,131		)

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	—		8,707		—		8,707
Less revenue recognized	—		8,707		677		9,384
Current deferred revenue, September 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		3,321		—		3,556
Noncurrent deferred revenue, September 30, 2016	$	29,237	$	19,805	$	—	$	49,042

As of September 30, 2016, accounts receivable included $3.8 million of total shortfall payment billings, none of which related to shortfall billings associated with MVC arrangements that can be utilized to offset gathering fees in future periods.

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9. DEBT

Debt consisted of the following:



	September 30, 2016			December 31, 2015
	(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (3.03% at September 30, 2016 and 2.93% at December 31, 2015) due November 2018	$	633,000		$	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)	(3,672		)	(4,139		)
Summit Holdings 7.50% Senior unsecured notes due July 2021	300,000			300,000
Unamortized deferred loan costs (2)	(4,409		)	(5,091		)
Total long-term debt	$	1,224,919		$	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 executed 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 5.5 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.

The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. Prior to the 2016 Drop Down, the revolving credit facility and Summit Holdings' obligations, were guaranteed by SMLP, Bison Midstream and its subsidiaries, Grand River and its subsidiary and DFW Midstream Services (the "Guarantor Subsidiaries" prior to the 2016 Drop Down).

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

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 September 30, 2016, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 3.03% and the unused portion of the revolving credit facility totaled $617.0 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

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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 September 30, 2016, we were in compliance with the revolving credit facility's covenants. There were no defaults or events of default during the nine months ended September 30, 2016.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," and 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").

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

As of September 30, 2016, we were in compliance with the covenants of the Senior Notes. There were no defaults or events of default during the nine months ended September 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 52% of total accounts receivable at September 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 Deferred Purchase Price Obligation involves significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a material effect on the ultimate cash payment and the Deferred Purchase Price Obligation. As such, its fair value measurement is classified as a non-recurring Level 3 measurement in the fair value hierarchy because our assumptions and judgments are not observable from objective sources (see Note 16).

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



	Three months ended September 30, 2016		Nine months ended September 30, 2016
	(In thousands)
Level 3 liability, beginning of period	$	532,355	$	—
Addition	—		507,427
Change in fair value	6,188		31,116
Level 3 liability, end of period	$	538,543	$	538,543

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



	September 30, 2016				December 31, 2015
	Carrying value		Estimated fair value (1)		Carrying value		Estimated fair value (1)
	(In thousands)
Summit Holdings revolving credit facility	$	633,000	$	633,000	$	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)	296,328		285,500		295,861		224,000
7.5% Senior Notes ($300.0 million principal)	295,591		307,875		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 September 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
Units issued in connection with the September 2016 Equity Offering	5,500,000	—		—	5,500,000
Contribution from general partner	—	—		112,245	112,245
Net units issued under SMLP LTIP	115,674	—		4,242	119,916
Subordinated units conversion	24,409,850	(24,409,850	)	—	—
Units, September 30, 2016	72,088,168	—		1,471,187	73,559,355

On September 9, 2016, we completed an underwritten public offering of 5,500,000 common units at a price of $23.20 per unit pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC (the "September 2016 Equity Offering"). Following the September 2016 Equity Offering, our general partner made a capital contribution to us to maintain its approximate 2% general partner interest. We used the net proceeds from the September 2016 Equity Offering to pay down our revolving credit facility.

Subordination. The subordination period ended in conjunction with the February 2016 distribution payment in respect of the fourth quarter of 2015 and the then-outstanding subordinated units converted to common units on a

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

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

Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of the 2016 Drop Down Assets 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 nine months ended September 30, 2016 and the three and nine months ended September 30, 2015 and


•	Polar and Divide during the nine months ended September 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 Note 16). In June 2016, we received a working capital adjustment of $0.6 million from a subsidiary of Summit Investments. We recognized a capital contribution from Summit Investments for the difference between (i) the net cash consideration paid and the Deferred Purchase Price Obligation and (ii) Summit Investments' net investment in the 2016 Drop Down Assets.

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



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 nine months ended September 30:



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Per-unit distributions to unitholders	$	0.575	$	0.570	$	1.725	$	1.695

On October 27, 2016, the board of directors of our general partner declared a distribution of $0.575 per unit for the quarterly period ended September 30, 2016. This distribution, which totaled $44.4 million, will be paid on November

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14, 2016 to unitholders of record at the close of business on November 7, 2016. We allocated the November 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 of the cash we distribute from operating surplus (see Note 11 to the consolidated financial statements included in our 2015 Annual Report). Our payment of IDRs to the general partner as included in distributions to unitholders follow.



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
IDR payments	$	1,938	$	1,831	$	5,811	$	4,807

For 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 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 September 30,					Nine months ended September 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	$	(215	)	$	13,412	$	(59,702	)	$	12,729
Net income attributable to subordinated units (1)				7,784					9,661
Net (loss) income attributable to limited partners	$	(215	)	$	21,196	$	(59,702	)	$	22,390

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	67,844			41,974		66,978			38,258
Effect of nonvested phantom units	—			173		—			129
Weighted-average common units outstanding – diluted	67,844			42,147		66,978			38,387

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

(Loss) earnings per limited partner unit:
Common unit – basic	$	0.00		$	0.32	$	(0.89	)	$	0.33
Common unit – diluted	$	0.00		$	0.32	$	(0.89	)	$	0.33
Subordinated unit – basic and diluted (1)				$	0.32				$	0.40

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU	—			—		167			63

__________

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

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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 September 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.

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



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
SMP Net Profits Interests noncash compensation	$	90	$	139	$	375	$	641

14. RELATED-PARTY TRANSACTIONS

Acquisitions. For information on the 2016 Drop Down and its funding, see Notes 1, 9, 11 and 16.

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 September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
Operation and maintenance expense	$	6,689	$	5,981	$	20,061	$	18,927
General and administrative expense	7,761		6,658		23,218		20,880

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 September 30,				Nine months ended September 30,
	2016		2015		2016		2015
	(In thousands)
Rent expense	$	754	$	621	$	2,115	$	1,810

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

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

In January 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream gathering system. 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	(2,628		)
Accrued environmental remediation, September 30, 2016	$	11,036

As of September 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 September 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

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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”) and (ii) includes a deferred payment in 2020 (the “Deferred Purchase Price Obligation”) (see Note 11).

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 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 September 30, 2016, Remaining Consideration was estimated to be $846.8 million and the net present value, as recognized on the consolidated balance sheet, was $538.5 million, using a discount rate of 13%. 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

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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.

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

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.

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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 September 30, 2015			Nine months ended September 30,
	Three months ended September 30, 2015			2016			2015
	(In thousands)
SMLP revenues	$	106,557		$	266,412		$	255,445
2016 Drop Down Assets revenues (1)	8,644			8,867			19,424
Polar and Divide revenues (1)							13,273
Combined revenues	$	115,201		$	275,279		$	288,142

SMLP net income (loss)	$	23,604		$	(54,927	)	$	28,256
2016 Drop Down Assets net (loss) income (1)	(20,063		)	2,745			(34,997		)
Polar and Divide net income (1)							5,403
Combined net income (loss)	$	3,541		$	(52,182	)	$	(1,338	)

__________

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

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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


•	each of SMLP and the Co-Issuers account for their subsidiary investments, if any, under the equity method of accounting and


•	the balances and results of operations associated with the assets, liabilities and expenses that were carved out of Summit Investments and allocated to SMLP in connection with the 2016 Drop Down have been attributed to SMLP during the common control period.

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



	September 30, 2016
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	4,022	$	385	$	2,107	$	1,083	$	—		$	7,597
Accounts receivable	50		—		42,841		9,557		—			52,448
Other current assets	1,160		—		2,979		627		—			4,766
Due from affiliate	16,336		28,050		344,180		—		(388,566		)	—
Total current assets	21,568		28,435		392,107		11,267		(388,566		)	64,811
Property, plant and equipment, net	2,100		—		1,444,558		406,400		—			1,853,058
Intangible assets, net	—		—		407,392		24,321		—			431,713
Investment in equity method investees	—		—		—		705,845		—			705,845
Goodwill	—		—		16,211		—		—			16,211
Other noncurrent assets	2,546		5,732		161		—		—			8,439
Investment in subsidiaries	2,093,929		3,292,414		—		—		(5,386,343		)	—
Total assets	$	2,120,143	$	3,326,581	$	2,260,429	$	1,147,833	$	(5,774,909	)	$	3,080,077

Liabilities and Partners' Capital
Trade accounts payable	$	741	$	—	$	6,018	$	6,351	$	—		$	13,110
Due to affiliate	372,344		—		—		16,336		(388,566		)	114
Ad valorem taxes payable	12		—		8,760		641		—			9,413
Accrued interest	—		7,733		—		—		—			7,733
Accrued environmental remediation	—		—		—		7,954		—			7,954
Other current liabilities	6,203		—		9,437		3,435		—			19,075
Total current liabilities	379,300		7,733		24,215		34,717		(388,566		)	57,399
Long-term debt	—		1,224,919		—		—		—			1,224,919
Deferred Purchase Price Obligation	538,543		—		—		—		—			538,543
Deferred revenue	—		—		49,042		—		—			49,042
Noncurrent accrued environmental remediation	—		—		—		3,082		—			3,082
Other noncurrent liabilities	2,900		—		4,775		17		—			7,692
Total liabilities	920,743		1,232,652		78,032		37,816		(388,566		)	1,880,677

Total partners' capital	1,199,400		2,093,929		2,182,397		1,110,017		(5,386,343		)	1,199,400
Total liabilities and partners' capital	$	2,120,143	$	3,326,581	$	2,260,429	$	1,147,833	$	(5,774,909	)	$	3,080,077

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	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
Other current assets	540		—		2,672		361		—			3,573
Due from affiliate	3,168		151,443		207,651		—		(362,262		)	—
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

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



	Three months ended September 30, 2016
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	64,065	$	16,231	$	—		$	80,296
Natural gas, NGLs and condensate sales	—			—			9,578		—		—			9,578
Other revenues	—			—			4,612		587		—			5,199
Total revenues	—			—			78,255		16,818		—			95,073
Costs and expenses:
Cost of natural gas and NGLs	—			—			6,986		—		—			6,986
Operation and maintenance	—			—			20,800		2,259		—			23,059
General and administrative	—			—			10,183		2,185		—			12,368
Depreciation and amortization	154			—			24,765		3,060		—			27,979
Loss on asset sales, net	—			—			13		—		—			13
Long-lived asset impairment	—			—			1,172		—		—			1,172
Total costs and expenses	154			—			63,919		7,504		—			71,577
Other income	51			—			—		—		—			51
Interest expense	—			(15,733		)	—		—		—			(15,733		)
Deferred Purchase Price Obligation expense	(6,188		)	—			—		—		—			(6,188		)
(Loss) income before income taxes and income from equity method investees	(6,291		)	(15,733		)	14,336		9,314		—			1,626
Income tax benefit	142			—			—		—		—			142
Income from equity method investees	—			—			—		270		—			270
Equity in earnings of consolidated subsidiaries	8,187			23,920			—		—		(32,107		)	—
Net income	$	2,038		$	8,187		$	14,336	$	9,584	$	(32,107	)	$	2,038

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	Three months ended September 30, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	93,480		$	8,094		$	—		$	101,574
Natural gas, NGLs and condensate sales	—			—			8,710			—			—			8,710
Other revenues	—			—			4,367			550			—			4,917
Total revenues	—			—			106,557			8,644			—			115,201
Costs and expenses:
Cost of natural gas and NGLs	—			—			6,959			—			—			6,959
Operation and maintenance	—			—			23,046			1,614			—			24,660
General and administrative	—			—			9,226			1,603			—			10,829
Transaction costs	322			—			—			—			—			322
Depreciation and amortization	138			—			23,974			2,284			—			26,396
Environmental remediation	—			—			—			20,000			—			20,000
Long-lived asset impairment	—			—			7,696			—			—			7,696
Total costs and expenses	460			—			70,901			25,501			—			96,862
Other income	1			—			—			—			—			1
Interest expense	(2,228		)	(12,119		)	(13		)	—			—			(14,360		)
(Loss) income before income taxes and loss from equity method investees	(2,687		)	(12,119		)	35,643			(16,857		)	—			3,980
Income tax expense	(199		)	—			—			—			—			(199		)
Loss from equity method investees	—			—			—			(240		)	—			(240		)
Equity in earnings of consolidated subsidiaries	6,427			18,546			—			—			(24,973		)	—
Net income (loss)	$	3,541		$	6,427		$	35,643		$	(17,097	)	$	(24,973	)	$	3,541

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	Nine months ended September 30, 2016
	SMLP			Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	191,510	$	43,073		$	—		$	234,583
Natural gas, NGLs and condensate sales	—			—			25,747		—			—			25,747
Other revenues	—			—			13,286		1,663			—			14,949
Total revenues	—			—			230,543		44,736			—			275,279
Costs and expenses:
Cost of natural gas and NGLs	—			—			20,140		—			—			20,140
Operation and maintenance	—			—			64,413		7,898			—			72,311
General and administrative	—			—			31,072		7,051			—			38,123
Transaction costs	1,296			—			—		—			—			1,296
Depreciation and amortization	424			—			74,194		9,052			—			83,670
Loss on asset sales, net	—			—			24		—			—			24
Long-lived asset impairment	—			—			1,212		529			—			1,741
Total costs and expenses	1,720			—			191,055		24,530			—			217,305
Other income	92			—			—		—			—			92
Interest expense	(1,441		)	(46,209		)	—		—			—			(47,650		)
Deferred Purchase Price Obligation expense	(31,116		)	—			—		—			—			(31,116		)
(Loss) income before income taxes and loss from equity method investees	(34,185		)	(46,209		)	39,488		20,206			—			(20,700		)
Income tax expense	(141		)	—			—		—			—			(141		)
Loss from equity method investees	—			—			—		(31,341		)	—			(31,341		)
Equity in (loss) earnings of consolidated subsidiaries	(17,856		)	28,353			—		—			(10,497		)	—
Net (loss) income	$	(52,182	)	$	(17,856	)	$	39,488	$	(11,135	)	$	(10,497	)	$	(52,182	)

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	Nine months ended September 30, 2015
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	222,085		$	17,683		$	—		$	239,768
Natural gas, NGLs and condensate sales	—			—			33,290			—			—			33,290
Other revenues	—			—			13,342			1,742			—			15,084
Total revenues	—			—			268,717			19,425			—			288,142
Costs and expenses:
Cost of natural gas and NGLs	—			—			24,974			—			—			24,974
Operation and maintenance	—			—			65,718			5,326			—			71,044
General and administrative	—			—			28,974			5,086			—			34,060
Transaction costs	1,254			—			—			—			—			1,254
Depreciation and amortization	488			—			71,357			6,100			—			77,945
Environmental remediation	—			—			—			20,000			—			20,000
Gain on asset sales, net	—			—			(214		)	—			—			(214		)
Long-lived asset impairment	—			—			7,696			—			—			7,696
Total costs and expenses	1,742			—			198,505			36,512			—			236,759
Other income	2			—			—			—			—			2
Interest expense	(8,529		)	(36,320		)	(14		)	—			—			(44,863		)
(Loss) income before income taxes and loss from equity method investees	(10,269		)	(36,320		)	70,198			(17,087		)	—			6,522
Income tax expense	(366		)	—			—			—			—			(366		)
Loss from equity method investees	—			—			—			(7,494		)	—			(7,494		)
Equity in earnings of consolidated subsidiaries	9,297			45,617			—			—			(54,914		)	—
Net (loss) income	$	(1,338	)	$	9,297		$	70,198		$	(24,581	)	$	(54,914	)	$	(1,338	)

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



	Nine months ended September 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	$	3,740		$	(52,916	)	$	159,650		$	58,231		$	—		$	168,705

Cash flows from investing activities:
Capital expenditures	(904		)	—			(39,630		)	(82,201		)	—			(122,735		)
Contributions to equity method investees	—			—			—			(20,157		)	—			(20,157		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(359,431		)	—			—			—			—			(359,431		)
Other, net	(373		)	—			—			—			—			(373		)
Advances to affiliates	(16,822		)	(245,093		)	(124,843		)	—			386,758			—
Net cash used in investing activities	(377,530		)	(245,093		)	(164,473		)	(102,358		)	386,758			(502,696		)

Cash flows from financing activities:
Distributions to unitholders	(123,064		)	—			—			—			—			(123,064		)
Borrowings under revolving credit facility	12,000			478,300			—			—			—			490,300
Repayments under revolving credit facility	—			(189,300		)	—			—			—			(189,300		)
Deferred loan costs	—			(3,013		)	—			—			—			(3,013		)
Proceeds from issuance of common units, net	126,115			—			—			—			—			126,115
Contribution from general partner	2,702			—			—			—			—			2,702
Cash advance (to) from Summit Investments (from) 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	(980		)	—			—			—			—			(980		)
Advances from affiliates	369,936			—			—			16,822			(386,758		)	—
Net cash provided by financing activities	377,739			285,987			—			42,827			(386,758		)	319,795
Net change in cash and cash equivalents	3,949			(12,022		)	(4,823		)	(1,300		)	—			(14,196		)
Cash and cash equivalents, beginning of period	73			12,407			6,930			2,383			—			21,793
Cash and cash equivalents, end of period	$	4,022		$	385		$	2,107		$	1,083		$	—		$	7,597

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	Nine months ended September 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	$	1,026		$	(45,034	)	$	157,931		$	24,174		$	—		$	138,097

Cash flows from investing activities:
Capital expenditures	(427		)	—			(89,643		)	(115,359		)	—			(205,429		)
Contributions to equity method investees	—			—			—			(74,375		)	—			(74,375		)
Acquisitions of gathering systems from affiliate, net of acquired cash	(288,618		)	—			—			—			—			(288,618		)
Other, net	—			—			238			—			—			238
Advances to affiliates	(1,811		)	(62,363		)	(96,100		)	—			160,274			—
Net cash used in investing activities	(290,856		)	(62,363		)	(185,505		)	(189,734		)	160,274			(568,184		)

Cash flows from financing activities:
Distributions to unitholders	(111,099		)	—			—			—			—			(111,099		)
Borrowings under revolving credit facility	170,000			147,000			—			—			—			317,000
Repayments under revolving credit facility	(100,000		)	(51,000		)	—			—			—			(151,000		)
Repayments under term loan	(180,000		)	—			—			—			—			(180,000		)
Deferred loan costs	(50		)	(154		)	—			—			—			(204		)
Proceeds from issuance of common units, net	222,014			—			—			—			—			222,014
Contribution from general partner	4,737			—			—			—			—			4,737
Cash advance from Summit Investments to contributed subsidiaries, net	110,000			—			21,719			160,687			—			292,406
Expenses paid by Summit Investments on behalf of contributed subsidiaries	9,825			—			3,864			2,950			—			16,639
Other, net	(1,435		)	—			(130		)	(1		)	—			(1,566		)
Advances from affiliates	158,463			—			—			1,811			(160,274		)	—
Net cash provided by financing activities	282,455			95,846			25,453			165,447			(160,274		)	408,927
Net change in cash and cash equivalents	(7,375		)	(11,551		)	(2,121		)	(113		)	—			(21,160		)
Cash and cash equivalents, beginning of period	7,531			11,621			7,353			1,306			—			27,811
Cash and cash equivalents, end of period	$	156		$	70		$	5,232		$	1,193		$	—		$	6,651

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


•	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 (see Notes 1 and 3 to the unaudited condensed consolidated financial statements).

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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. During the nine months ended September 30, 2016, we generated approximately 90% of our revenues from fee-based gathering services and the remainder largely comprised revenues generated from percent-of-proceeds arrangements and various by-product hydrocarbon sales.

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, (iii) the sale of natural gas we retain from our DFW Midstream customers and (iv) 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 certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs ensure that we will recognize a minimum amount of revenue.

The following table presents certain consolidated and reportable segment financial data.



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(In thousands)
Selected Financial Results:
Net income (loss)	$	2,038		$	3,541		$	(52,182	)	$	(1,338	)
Reportable segment adjusted EBITDA:
Utica Shale (1)	$	17,042		$	11,031		$	50,071		$	22,651
Williston Basin	21,815			(5,800		)	60,745			17,817
Piceance/DJ Basins	28,074			26,162			79,120			83,070
Barnett Shale	13,128			13,143			41,118			45,444
Marcellus Shale	5,146			5,795			14,554			18,492

Net cash provided by operating activities	$	37,205		$	33,101		$	168,705		$	138,097
Acquisitions of gathering systems (2)	—			(4,323		)	866,858			288,618
Capital expenditures	31,363			73,912			122,735			205,429
Contributions to equity method investees	4,512			9,979			20,157			74,375

Distributions to unitholders	$	41,044		$	40,480		$	123,064		$	111,099
(Repayments) borrowings under revolving credit facility, net	(88,000		)	60,000			301,000			166,000
Proceeds from issuance of common units, net	126,115			*			126,115			222,014

_________

* Not considered meaningful

(1) Includes our proportional share of adjusted EBITDA for Ohio Gathering, based on a one-month lag.

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

Three and nine months ended September 30, 2016. The following items are reflected in our financial results:


•	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 the Deferred Purchase Price Obligation with Summit Investments (see Notes 9, 11 and 16 to the unaudited condensed consolidated financial statements).

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•

In June 2016, an impairment loss was recognized by OCC. We recorded our 40% share of the impairment loss, or $37.8 million, in income (loss) from equity method investees in the unaudited condensed consolidated statements of operations. We exclude income or loss from equity method investees from our definition of segment adjusted EBITDA. As such, Utica Shale segment adjusted EBITDA was not impacted by the impairment loss (see Note 7 to the unaudited condensed consolidated financial statements).


•	In September 2016, we completed an underwritten public offering of 5,500,000 common units at a price of $23.20 per unit and used the net proceeds to pay down our revolving credit facility. Following the offering, our general partner made a capital contribution to us to maintain its approximate 2% general partner interest.

Three and nine months ended September 30, 2015. The following items are reflected in our financial results:


•	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 (see Notes 9, 11 and 16 to the consolidated financial statements included in the 2015 Annual Report).

•

In September 2015, we recognized $34.4 million of gathering services and related fees revenue that had been previously deferred in connection with an MVC arrangement with a certain Piceance/DJ Basins customer, which was determined to no longer be recoverable by the customer. We include the effect of adjustments related to MVC shortfall payments in our definition of segment adjusted EBITDA. As such, Piceance/DJ Basins segment adjusted EBITDA was not impacted because the revenue recognition was offset by the associated adjustments related to MVC shortfall payments for this customer (see Note 8 to the consolidated financial statements included in the 2015 Annual Report).


•	In September 2015, we recognized an additional accrual for environmental remediation expenses of $20.0 million associated with the rupture of a produced water gathering pipeline in the Williston Basin reportable segment (see Note 15 to the consolidated financial statements included in the 2015 Annual Report).

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 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.

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resources in connection with our operations (see Note 3 to the unaudited condensed consolidated financial statements).

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


•	throughput volume,


•	revenues,


•	operation and maintenance expenses and


•	segment adjusted EBITDA.

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 since December 31, 2015, except as updated below.

Segment Adjusted EBITDA

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

Segment adjusted EBITDA is used to assess:


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


•	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;


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


•	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 commitment shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.

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

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Results of Operations

Consolidated Overview of the Three and Nine Months Ended September 30, 2016 and 2015

The following table presents certain consolidated and operating data.



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(In thousands)
Revenues:
Gathering services and related fees	$	80,296		$	101,574		$	234,583		$	239,768
Natural gas, NGLs and condensate sales	9,578			8,710			25,747			33,290
Other revenues	5,199			4,917			14,949			15,084
Total revenues	95,073			115,201			275,279			288,142
Costs and expenses:
Cost of natural gas and NGLs	6,986			6,959			20,140			24,974
Operation and maintenance	23,059			24,660			72,311			71,044
General and administrative	12,368			10,829			38,123			34,060
Transaction costs	—			322			1,296			1,254
Depreciation and amortization	27,979			26,396			83,670			77,945
Environmental remediation	—			20,000			—			20,000
Loss (gain) on asset sales, net	13			—			24			(214		)
Long-lived asset impairment	1,172			7,696			1,741			7,696
Total costs and expenses	71,577			96,862			217,305			236,759
Other income	51			1			92			2
Interest expense	(15,733		)	(14,360		)	(47,650		)	(44,863		)
Deferred Purchase Price Obligation expense	(6,188		)	—			(31,116		)	—
Income (loss) before income taxes and income (loss) from equity method investees	1,626			3,980			(20,700		)	6,522
Income tax benefit (expense)	142			(199		)	(141		)	(366		)
Income (loss) from equity method investees	270			(240		)	(31,341		)	(7,494		)
Net income (loss)	$	2,038		$	3,541		$	(52,182	)	$	(1,338	)

Operating Data:
Aggregate average throughput – gas (MMcf/d)	1,572			1,446			1,536			1,533
Aggregate average throughput rate per Mcf – gas	$	0.45		$	0.42		$	0.45		$	0.42
Average throughput – liquids (Mbbl/d)	92.2			68.2			91.0			61.5
Aggregate average throughput rate per Bbl – liquids	$	1.77		$	1.79		$	1.86		$	1.79

Volumes – Gas. Aggregate natural gas throughput volumes increased during the three months ended September 30, 2016 primarily reflecting:


•	a volume throughput increase of 192 MMcf/d for the Utica Shale segment;


•	a volume throughput decrease of 39 MMcf/d for the Marcellus Shale segment; and


•	a volume throughput decrease of 20 MMcf/d for the Barnett Shale segment.

Aggregate natural gas throughput volumes were flat during the nine months ended September 30, 2016 primarily reflecting:


•	a volume throughput increase of 154 MMcf/d for the Utica Shale segment;


•	a volume throughput decrease of 86 MMcf/d for the Marcellus Shale segment;

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•	a volume throughput decrease of 35 MMcf/d for the Piceance/DJ Basins segment; and


•	a volume throughput decrease of 32 MMcf/d for the Barnett Shale segment.

Volumes – Liquids. Average daily throughput for crude oil and produced water increased during the three and nine months ended September 30, 2016 primarily reflecting new pad site connections and producers' drilling activity on the Polar and Divide system. The year-to-date increase was partially offset by the second quarter 2016 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 volume throughput in the first nine months of 2015 (see Note 15 to the unaudited condensed consolidated financial statements).

Revenues. Total revenues decreased $20.1 million, or 17%, during the three months ended September 30, 2016 primarily reflecting:


•	a $32.3 million decline in gathering services and related fees for the Piceance/DJ Basins segment;


•	a $6.3 million increase in gathering services and related fees for the Utica Shale segment; and


•	a $5.9 million increase in gathering services and related fees for the Williston Basin segment.

Total revenues decreased $12.9 million, or 4%, during the nine months ended September 30, 2016 primarily reflecting:


•	a $32.0 million decline in gathering services and related fees for the Piceance/DJ Basins segment;


•	a $7.5 million decrease in natural gas, NGLs and condensate sales;


•	a $6.0 million decrease in gathering services and related fees for the Barnett Shale segment;


•	a $20.3 million increase in gathering services and related fees for the Williston Basin segment; and


•	a $15.1 million increase in gathering services and related fees for the Utica Shale segment

Gathering Services and Related Fees. The decrease in gathering services and related fees during the three months ended September 30, 2016 was primarily driven by the recognition of $34.4 million of deferred revenue that occurred in September 2015 for a certain Piceance/DJ Basins customer. This decrease was partially offset by (i) an increase of $6.3 million for the Utica Shale segment due to the development of the Summit Utica system and (ii) an increase of $5.9 million for the Williston Basin segment due to higher volume throughput on the Polar and Divide system and the development of the Tioga Midstream system.

The aggregate average throughput rate for natural gas increased to $0.45/Mcf during the three months ended September 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 was relatively flat at $1.77/Bbl during the three months ended September 30, 2016, compared with $1.79/Bbl in the prior-year period.

The decrease in gathering services and related fees during the nine months ended September 30, 2016 was primarily driven by the recognition of $34.4 million of deferred revenue that occurred in September 2015 for a certain Piceance/DJ Basins customer as well as the effect of a decrease of $6.0 million for the Barnett Shale segment due to declining volume throughput at DFW Midstream. This decrease was partially offset by (i) an increase of $20.3 million for the Williston Basin segment due to higher volume throughput on the Polar and Divide system and the development of the Tioga Midstream system and (ii) an increase of $15.1 million for the Utica Shale segment due to the development of the Summit Utica system.

The aggregate average throughput rate for natural gas increased to $0.45/Mcf during the nine months ended September 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 nine months ended September 30, 2016, compared with $1.79/Bbl in the prior-year period primarily as a result of rate redeterminations which were in effect during the first half of 2016 for Tioga Midstream.

Natural Gas, NGLs and Condensate Sales. The increase in natural gas, NGLs and condensate sales for the three months ended September 30, 2016 was primarily a result of the impact of higher commodity prices relative to the third quarter of 2015.

The decrease in natural gas, NGLs and condensate sales for the nine months ended September 30, 2016 was primarily a result of the impact of lower commodity prices during the first half of 2016.

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Costs and Expenses. Total costs and expenses decreased $25.3 million, or 26%, for the three months ended September 30, 2016, primarily reflecting:


•	the September 2015 recognition of an additional accrual of $20.0 million for environmental remediation expenses associated with a produced water pipeline that became part of the Polar and Divide system in connection with the 2016 Drop Down and


•	the September 2015 recognition of $7.7 million of long-lived asset impairments.

Total costs and expenses decreased $19.5 million, or 8%, for the nine months ended September 30, 2016 primarily reflecting:


•	the September 2015 recognition of an additional accrual of $20.0 million for environmental remediation expenses associated with a produced water pipeline that became part of the Polar and Divide system in connection with the 2016 Drop Down.


•	a $4.8 million decrease in cost of natural gas and NGLs primarily due to the impact of lower commodity prices at Bison Midstream and Grand River during the first half of 2016.


•	a $5.7 million increase in depreciation and amortization for all segments.


•	a $4.1 million increase in general and administrative expense primarily due to an increase in salaries, benefits and incentive compensation as a result of increased head count.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs was relatively flat during the three months ended September 30, 2016 and reflected the offsetting effects of an increase for Bison Midstream and a decrease for Grand River.

The decrease in cost of natural gas and NGLs during the nine months ended September 30, 2016 was largely driven by lower comparative commodity prices during the first half of 2016 and the associated impact on (i) our percent-of-proceeds arrangements at Bison Midstream and Grand River and (ii) condensate sales at Grand River.

Operation and Maintenance. Operation and maintenance expense decreased during the three months ended September 30, 2016 primarily reflecting a decline in general operating expenses.

Operation and maintenance expense increased during the nine months ended September 30, 2016 primarily reflecting overall increases for the development of the Summit Utica, Tioga Midstream and Polar and Divide systems.

General and Administrative. General and administrative expense increased during the three months ended September 30, 2016 primarily reflecting an increase in expenses for salaries and benefits.

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

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 nine months ended September 30, 2016 was largely driven by an increase in assets placed into service.

Interest Expense. The increase in interest expense during the three and nine months ended September 30, 2016 was primarily driven by (i) higher borrowing costs associated with our revolving credit facility and (ii) the Summit Investments' debt allocated to the 2016 Drop Down Assets. The revolving credit facility borrowings incurred in March 2016 in connection with the 2016 Drop Down replaced the lower-rate Summit Investments' debt that had been allocated to us prior to our March 2016 closing of the 2016 Drop Down, resulting in an increase in interest expense.

Deferred Purchase Price Obligation Expense. Deferred Purchase Price Obligation expense recognized during the three and nine months ended September 30, 2016 relates to the deferred payment recognized in connection with the 2016 Drop Down (see Notes 2 and 16 to the unaudited condensed consolidated financial statements).

For additional information, see the "Segment Overview of the Three and Nine Months Ended September 30, 2016 and 2015" and "Corporate Overview of the Three and Nine Months Ended September 30, 2016 and 2015" sections herein.

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Segment Overview of the Three and Nine Months Ended September 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 September 30,		Percentage Change	Nine months ended September 30,		Percentage Change
	2016	2015	Percentage Change	2016	2015	Percentage Change
Average throughput (MMcf/d) (2)	234	42	*	178	24	*

__________

* Not considered meaningful

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

(2) Does not include volume throughput for Ohio Gathering.

Volume throughput for the three and nine months ended September 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.

Financial data for our Utica Shale reportable segment follows.



	Utica Shale
	Three months ended September 30,				Percentage Change		Nine months ended September 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,665	$	1,354	*		$	17,351	$	2,258	*
Total revenues	7,665		1,354		*		17,351		2,258		*
Costs and expenses:
Operation and maintenance	564		125		*		1,585		629		*
General and administrative	118		375		(69	)%	868		970		(11	)%
Depreciation and amortization	961		335		*		2,756		691		*
Total costs and expenses	1,643		835		97	%	5,209		2,290		127	%
Add:
Proportional adjusted EBITDA for equity method investees (1)	10,059		10,177				35,173		21,992
Depreciation and amortization	961		335				2,756		691
Segment adjusted EBITDA	$	17,042	$	11,031	54	%	$	50,071	$	22,651	121	%

__________

* Not considered meaningful

(1) Represents our proportional share of adjusted EBITDA for Ohio Gathering, based on a one-month lag.

Three months ended September 30, 2016. Segment adjusted EBITDA increased $6.0 million during the three months ended September 30, 2016 primarily reflecting the growth and development of Summit Utica.

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

Nine months ended September 30, 2016. Segment adjusted EBITDA increased $27.4 million during the nine months ended September 30, 2016 reflecting:


•	the growth and development of Summit Utica.


•	an increase in Ohio Gathering's adjusted EBITDA due to growth and development in the first half of 2016. This impact was partially offset by the deceleration of volume growth for both OGC and OCC, which began in the third quarter of 2016.

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Depreciation and amortization increased over 2015 largely 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.

Operating data for our Williston Basin reportable segment follows.



	Williston Basin
	Three months ended September 30,				Percentage Change		Nine months ended September 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	$	2.71	$	2.25	20	%	$	2.70	$	2.35	15	%
Average throughput – liquids (Mbbl/d)	92.2		68.2		35	%	91.0		61.5		48	%
Average throughput rate per Bbl – liquids	$	1.77	$	1.79	(1	)%	$	1.86	$	1.79	4	%

Natural gas. Natural gas volume throughput increased during the three and nine months ended September 30, 2016 largely as a result of 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 due to 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 nine months ended September 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 was in effect in the first and second quarters of 2016.

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Financial data for our Williston Basin reportable segment follows.



	Williston Basin
	Three months ended September 30,					Percentage Change		Nine months ended September 30,				Percentage Change
	2016		2015 (1)			Percentage Change		2016		2015 (1)		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	21,293	$	15,421		38	%	$	63,244	$	42,905	47	%
Natural gas, NGLs and condensate sales	5,815		4,959			17	%	15,010		18,208		(18	)%
Other revenues	3,086		2,973			4	%	9,456		8,958		6	%
Total revenues	30,194		23,353			29	%	87,710		70,071		25	%
Costs and expenses:
Cost of natural gas and NGLs	5,739		4,841			19	%	15,344		17,808		(14	)%
Operation and maintenance	6,335		7,103			(11	)%	21,536		19,180		12	%
General and administrative	500		679			(26	)%	2,077		4,321		(52	)%
Depreciation and amortization	8,446		8,003			6	%	25,214		23,100		9	%
Environmental remediation	—		20,000			*		—		20,000		*
Loss on asset sales, net	13		—			*		15		—		*
Long-lived asset impairment	—		7,696			*		569		7,696		*
Total costs and expenses	21,033		48,322			(56	)%	64,755		92,105		(30	)%
Add:
Depreciation and amortization	8,446		8,003					25,214		23,100
Adjustments related to MVC shortfall payments	4,195		3,470					11,992		8,970
Loss on asset sales	34		—					15		—
Long-lived asset impairment	—		7,696					569		7,696
Unit-based compensation	—		—					—		85
Less:
Gain on asset sales	21		—					—		—
Segment adjusted EBITDA	$	21,815	$	(5,800	)	*		$	60,745	$	17,817	*

__________

* 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 September 30, 2016. Segment adjusted EBITDA increased $27.6 million during the three months ended September 30, 2016 reflecting:


•	the September 2015 recognition of an additional accrual of $20.0 million for environmental remediation costs associated with a produced water pipeline that became part of the Polar and Divide system in connection with the 2016 Drop Down.


•	an increase in gathering services and related fees primarily as a result of higher volume throughput due to the development of the Polar and Divide and Tioga Midstream systems.


•	a decrease in operation and maintenance expense largely as a result of the impact of certain repairs and maintenance that were partially offset by an increase in compensation-related expenses.

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Other items to note:


•	In September 2015, we impaired certain property, plant and equipment balances associated with terminated projects. These impairments had no impact on segment adjusted EBITDA for the three months ended September 30, 2015.


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

Nine months ended September 30, 2016. Segment adjusted EBITDA increased $42.9 million during the nine months ended September 30, 2016 reflecting:


•	the September 2015 recognition of an additional accrual of $20.0 million for environmental remediation costs associated with a produced water pipeline that became part of the Polar and Divide system in connection with the 2016 Drop Down.

•

an increase in gathering services and related fees primarily due to (i) the development of the Polar and Divide and Tioga Midstream systems and (ii) higher gathering rates associated with a rate redetermination, which was in effect in the first and second quarters of 2016. These contributors were partially offset by the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines.


•	an increase in operation and maintenance expense largely as a result of system buildout on the Polar and Divide and Tioga Midstream systems during the first half of 2016 and certain environmental remediation expenses not associated with the produced water pipeline incident noted above.


•	a decrease in general and administrative expense largely as a result of a higher allocation of certain corporate general and administrative expenses in 2015 for both the Polar and Divide and Tioga Midstream systems (see the "—Corporate—General and Administrative" section herein).

Other items to note:


•	In September 2015, we impaired certain property, plant and equipment balances associated with terminated projects. These impairments had no impact on segment adjusted EBITDA for the nine months ended September 30, 2015.


•	Depreciation and amortization increased during nine months ended September 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.

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



	Piceance/DJ Basins
	Three months ended September 30,				Percentage Change		Nine months ended September 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
Average throughput (MMcf/d)	591		599		(1	)%	576		611		(6	)%
Average throughput rate per Mcf (1)	$	0.51	$	0.46	11	%	$	0.50	$	0.46	9	%

__________

(1) Excludes the revenue impact associated with the recognition of certain previously deferred revenues (see Note 8 to the audited consolidated financial statements included in the 2015 Annual Report.)

Volume throughput was relatively flat during the three months ended September 30, 2016 primarily as a result of the offsetting effects of (i) natural production declines, (ii) the continued suspension of drilling activities by one of Grand River's anchor customers and (iii) an increase in volume throughput by other producer customers. The aggregate average throughput rate increased during 2016 largely as a result of a shift in volume throughput mix.

Volume throughput decreased during the nine months ended September 30, 2016 primarily as a result of the continued suspension of drilling activities by one of Grand River's anchor customers and the resulting natural

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declines from existing production. The impact of these decreases were partially offset by an increase in volume throughput by other producer customers. The aggregate average throughput rate increased during 2016 largely as a result of a shift in volume throughput mix.

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



	Piceance/DJ Basins
	Three months ended September 30,					Percentage Change		Nine months ended September 30,					Percentage Change
	2016		2015			Percentage Change		2016		2015			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	27,497	$	59,819		(54	)%	$	78,289	$	110,328		(29	)%
Natural gas, NGLs and condensate sales	1,784		2,186			(18	)%	6,412		9,897			(35	)%
Other revenues	1,795		1,738			3	%	4,778		5,495			(13	)%
Total revenues	31,076		63,743			(51	)%	89,479		125,720			(29	)%
Costs and expenses:
Cost of natural gas and NGLs	1,247		2,118			(41	)%	4,796		7,166			(33	)%
Operation and maintenance	8,485		9,701			(13	)%	25,268		27,622			(9	)%
General and administrative	529		852			(38	)%	2,527		2,721			(7	)%
Depreciation and amortization	12,273		11,854			4	%	36,843		35,454			4	%
Loss (gain) on asset sales, net	—		—			*		9		(214		)	*
Total costs and expenses	22,534		24,525			(8	)%	69,443		72,749			(5	)%
Add:
Depreciation and amortization	12,273		11,854					36,843		35,454
Adjustments related to MVC shortfall payments	7,259		(24,910		)			22,232		(5,141		)
Loss on asset sales	—		—					71		24
Add:
Gain on asset sales	—		—					62		238
Segment adjusted EBITDA	$	28,074	$	26,162		7	%	$	79,120	$	83,070		(5	)%

__________

* Not considered meaningful

Three months ended September 30, 2016. Segment adjusted EBITDA increased $1.9 million during the three months ended September 30, 2016 reflecting:


•	a decrease in gathering services and related fees primarily due to the impact of declining volumes from one of Grand River's anchor customers. This impact was largely offset by higher average throughput rates due to a shift in customer mix.


•	a decrease in operation and maintenance largely as a result of declines in general repairs and maintenance expenses and an adjustment to our property tax expense accrual.

Other items to note:

•

A portion of the change 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, the decrease in gathering services and related fees from the third quarter of 2015 was offset by the change 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).

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Nine months ended September 30, 2016. Segment adjusted EBITDA decreased $4.0 million during the nine months ended September 30, 2016 reflecting:


•	a decrease in gathering services and related fees primarily as a result of declining volumes from one of Grand River's anchor customers. This impact was partially offset by higher average throughput rates due to a shift in customer mix.


•	a decrease in operation and maintenance primarily due to lower general repairs and maintenance expenses.

Other items to note:


•	Depreciation and amortization increased during the nine months ended September 30, 2016 largely as a result of an increase in contract amortization for one of Grand River's anchor customers.

•

A portion of the change 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, the decrease in gathering services and related fees from the first nine months of 2015 was offset by the change 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).

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 September 30,				Percentage Change		Nine months ended September 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
Average throughput (MMcf/d)	305		325		(6	)%	329		361		(9	)%
Average throughput rate per Mcf	$	0.60	$	0.58	3	%	$	0.60	$	0.62	(3	)%

Volume throughput declined during the three months ended September 30, 2016 reflecting production declines due to reduced drilling activity and natural production declines as well as an annual shutdown of the DFW Midstream system which occurred in September 2016. The prior-year shutdown occurred in October 2015. The impact of these items was partially offset by the commissioning of an 11-well pad site in the second quarter of 2016.

Volume throughput declined during the nine months ended September 30, 2016 reflecting reduced drilling activity and natural production declines, partially offset by the commissioning of an 11-well pad site in the second quarter of 2016 and the commissioning of 14 wells in December 2015 and January 2016.

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Financial data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Three months ended September 30,				Percentage Change		Nine months ended September 30,						Percentage Change
	2016		2015		Percentage Change		2016			2015			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	17,193	$	18,017	(5	)%	$	55,707		$	61,692		(10	)%
Natural gas, NGLs and condensate sales	1,979		1,565		26	%	4,325			5,185			(17	)%
Other revenues	318		206		54	%	715			631			13	%
Total revenues	19,490		19,788		(2	)%	60,747			67,508			(10	)%
Costs and expenses:
Operation and maintenance	6,291		6,648		(5	)%	18,782			19,796			(5	)%
General and administrative	280		268		4	%	829			1,001			(17	)%
Depreciation and amortization	3,921		3,896		1	%	11,767			11,704			1	%
Long-lived asset impairment	1,172		—		*		1,172			—			*
Total costs and expenses	11,664		10,812		8	%	32,550			32,501			—	%
Add:
Depreciation and amortization	4,043		4,081				12,155			12,352
Adjustments related to MVC shortfall payments	87		86				(406		)	(1,915		)
Long-lived asset impairment	1,172		—				1,172			—
Segment adjusted EBITDA	$	13,128	$	13,143	—	%	$	41,118		$	45,444		(10	)%

Three months ended September 30, 2016. Segment adjusted EBITDA was flat during the three months ended September 30, 2016 reflecting:


•	a decline in gathering services and related fees primarily due to reduced volume throughput.


•	an increase in natural gas, NGLs and condensate sales primarily due to higher commodity prices. This impact was partially offset by 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.


•	a decrease in operation and maintenance largely as a result of an adjustment to our accrual for property tax expenses.

The long-lived asset impairment reflects our September 2016 decision to impair certain property, plant and equipment balances associated with the decommissioning of certain assets.

Nine months ended September 30, 2016. Segment adjusted EBITDA decreased $4.3 million during the nine months ended September 30, 2016 reflecting:


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


•	a decrease in natural gas, NGLs and condensate sales primarily due to the impact of (i) lower commodity prices in the first half of 2016 and (ii) 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.


•	a decrease in operation and maintenance expense largely as a result of lower electricity expense. 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 during the first half of 2016 and lower volume throughput for the nine-month period of 2016 translated into lower electricity expenses.

The long-lived asset impairment reflects our September 2016 decision to impair certain property, plant and equipment balances associated with the decommissioning of certain assets.

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

Volume throughput for our Marcellus Shale reportable segment follows.



	Marcellus Shale (1)
	Three months ended September 30,		Percentage Change		Nine months ended September 30,		Percentage Change
	2016	2015	Percentage Change		2016	2015	Percentage Change
Average throughput (MMcf/d)	418	457	(9	)%	429	515	(17	)%

__________

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

Volume throughput declined during the three and nine months ended September 30, 2016 due to our anchor customer’s decision to defer completion activities in the third quarter of 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 and July 2016 limiting the amount of natural gas we could deliver during the repair work. The repairs to the third-party NGL pipeline were completed in early July 2016 and volume throughput on the Mountaineer Midstream system resumed at levels commensurate with the second quarter of 2016 prior to the incident.

Financial data for our Marcellus Shale reportable segment follows.



	Marcellus Shale
	Three months ended September 30,				Percentage Change		Nine months ended September 30,				Percentage Change
	2016		2015		Percentage Change		2016		2015		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,648	$	6,963	(5	)%	$	19,992	$	22,585	(11	)%
Total revenues	6,648		6,963		(5	)%	19,992		22,585		(11	)%
Costs and expenses:
Operation and maintenance	1,384		1,083		28	%	5,140		3,817		35	%
General and administrative	118		85		39	%	298		276		8	%
Depreciation and amortization	2,224		2,170		2	%	6,665		6,508		2	%
Total costs and expenses	3,726		3,338		12	%	12,103		10,601		14	%
Add:
Depreciation and amortization	2,224		2,170				6,665		6,508
Segment adjusted EBITDA	$	5,146	$	5,795	(11	)%	$	14,554	$	18,492	(21	)%

Three months ended September 30, 2016. Segment adjusted EBITDA decreased $0.6 million during the three months ended September 30, 2016 reflecting:


•	a decrease in gathering services and related fees primarily as a result of lower volume throughput and lower compression revenues due to a shift in throughput mix. These declines were partially offset by an increase in minimum revenue commitment payments.


•	an increase in operation and maintenance primarily as a result of an adjustment to our accrual for property tax expenses.

Nine months ended September 30, 2016. Segment adjusted EBITDA decreased $3.9 million during the nine months ended September 30, 2016 reflecting:


•	a decrease in gathering services and related fees primarily as a result of lower volume throughput and lower compression revenues due to a shift in volume mix. These declines were partially offset by an increase in minimum revenue commitment payments.


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

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Corporate Overview of the Three and Nine Months Ended September 30, 2016 and 2015

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 September 30,		Percentage Change		Nine months ended September 30,		Percentage Change
	2016	2015	Percentage Change		2016	2015	Percentage Change
	(Dollars in thousands)
Costs and expenses:
General and administrative	10,823	8,570	26	%	31,524	24,771	27	%
Transaction costs	—	322	*		1,296	1,254	3	%
Interest expense (1)	15,733	14,360	10	%	47,650	44,863	6	%
Deferred Purchase Price Obligation expense	6,188	—	*		31,116	—	*

__________

* Not considered meaningful

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

General and Administrative. The increase in general and administrative expenses during the three and nine months ended September 30, 2016 reflects the impact of a change in our expense allocation methodology as well as increases in salaries, benefits and incentive compensation primarily due to increased head count. In the first quarter of 2015, the Partnership discontinued allocating certain administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to its then-reportable segments. As a result, general and administrative expense allocations were higher for Polar and Divide and the 2016 Drop Down Assets during their respective common control periods because Summit Investments continued to allocate these administrative expenses to its non-Partnership subsidiaries. With respect to Polar and Divide, general and administrative expense allocations during the period from January 1, 2015 to May 18, 2015 included items that SMLP was no longer allocating to its then-operating segments. With respect to the 2016 Drop Down Assets, general and administrative expense allocations during the period from January 1, 2015 to March 3, 2016 included items that SMLP was no longer allocating to its then-operating segments. As such, subsequent to a given drop down, the application of the new expense allocation methodology resulted in a decrease in reportable segment general and administrative expenses and an increase in corporate general and administrative expenses.

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).

Liquidity and Capital Resources

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

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Capital Markets Activity

Capital markets activity during the nine months ended September 30, 2016 follows.

November 2013 Shelf Registration Statement. On September 9, 2016, we completed an underwritten public offering of 5,500,000 common units at a price of $23.20 per unit pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC. Following the offering, our general partner made a capital contribution to us to maintain its approximate 2% general partner interest. We used the net proceeds therefrom to pay down our revolving credit facility.

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 September 30, 2016, the outstanding balance of the revolving credit facility was $633.0 million and the unused portion totaled $617.0 million. There were no defaults or events of default during 2016 and, as of September 30, 2016, we were in compliance with the covenants in the revolving credit facility (see Notes 9 and 17 to the unaudited condensed consolidated financial statements).

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



	Nine months ended September 30,
	2016			2015
	(In thousands)
Net cash provided by operating activities	$	168,705		$	138,097
Net cash used in investing activities	(502,696		)	(568,184		)
Net cash provided by financing activities	319,795			408,927
Net change in cash and cash equivalents	$	(14,196	)	$	(21,160	)

Operating activities. Cash flows from operating activities increased by $30.6 million from the nine months ended September 30, 2015 to the nine months ended September 30, 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 $10.7 million increase in distributions from Ohio Gathering.

Investing activities. Cash flows used in investing activities during the nine months ended September 30, 2016 primarily reflected:


•	$359.4 million for our acquisition of the 2016 Drop Down Assets;


•	$122.7 million of capital expenditures primarily attributable to the ongoing expansion of the 2016 Drop Down Assets and the Polar and Divide system.

Cash flows used in investing activities during the nine months ended September 30, 2015 primarily reflected:


•	$288.6 million for our acquisition of the Polar and Divide system.


•	$205.4 million of capital expenditures primarily attributable to the buildout of the gathering systems acquired in the 2016 Drop Down and the ongoing expansion of the Polar and Divide and Bison Midstream systems;

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Financing activities. Net cash provided by financing activities during the nine months ended September 30, 2016 primarily reflects:


•	$301.0 million of net borrowings under our revolving credit facility, of which, $360.0 million was borrowed to fund the 2016 Drop Down;


•	$126.1 million of net proceeds from the issuance of common units in September 2016, all of which was used to pay down the revolving credit facility; and


•	$123.1 million of distributions paid in 2016.

Net cash provided by financing activities during the nine months ended September 30, 2015 primarily reflects:


•	$292.4 million of cash advances from Summit Investments to fund the development of the 2016 Drop Down Assets;


•	$222.0 million of net proceeds from the issuance of common units, of which $193.4 million was used to partially fund the Polar and Divide Drop Down;


•	$166.0 million of net borrowings under our revolving credit facility, of which $92.0 million was used to partially fund the Polar and Divide Drop Down; and


•	$111.1 million of distributions 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. Additional interest expense on the incremental $360.0 million of 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 $846.8 million based on information available as of September 30, 2016. There are no cash interest payments associated with the Deferred Purchase Price Obligation.

Capital Requirements

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 nine months ended September 30, 2016, cash paid for capital expenditures totaled $122.7 million, compared with $205.4 million in the prior-year period (see Note 3 to the unaudited condensed consolidated financial statements). Maintenance capital expenditures totaled $13.4 million for the nine months ended September 30, 2016, compared with $9.6 million in the prior-year period.

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

We believe that our revolving credit facility, together with financial support from our Sponsor and/or access to the debt and equity capital markets, will be adequate to finance our 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

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the third target distribution in connection with the distribution declared in respect of the second quarter of 2014 (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 segment 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 (see Notes 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 nine months ended September 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 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 nine months ended September 30, 2016, except as noted below.

Recognition and Impairment of Long-Lived Assets

Goodwill. As of September 30, 2016, Mountaineer Midstream is our only reporting unit with goodwill. We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. We test goodwill for impairment using a two-step quantitative test. In the first step, we compare the fair value of the reporting unit to its carrying value, including goodwill. If the reporting unit’s fair value exceeds its carrying value, including goodwill, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value, including goodwill, exceeds its fair value, we proceed to step two. In step two, we compare the carrying value of the reporting unit, including goodwill, to its implied fair value. If we determine that the carrying value of a reporting unit, including goodwill, exceeds its implied fair value, we recognize the excess of the carrying value over the implied fair value as a goodwill impairment loss.

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

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Grand River and Polar and Divide Fourth Quarter 2015 Goodwill Impairment. 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.

Deferred Purchase Price Obligation

We recognized the Deferred Purchase Price Obligation to reflect the present value of the Remaining Consideration. Our calculation of the Remaining Consideration incorporates estimates of (i) capital expenditures made between the respective balance sheet date and December 31, 2019 and (ii) Business Adjusted EBITDA, an income-based measure, during the period from the respective balance sheet date 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 consolidated balance sheets with the change in present value recognized in earnings in the period of change.

The estimates and expectations used in the calculating the prospective component of Remaining Consideration and the present value calculation of the Remaining Consideration involve a significant amount of judgment as the calculations are based on future events and/or conditions, including (i) 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.

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

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;


•	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;

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•

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 September 30, 2016, we had $600.0 million principal of fixed-rate senior notes and $633.0 million of variable rate debt (see Note 9 to the unaudited condensed consolidated financial statements). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our revolving credit facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, 2015. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2015 Annual Report.

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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. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2015 Annual Report.

Item 4. Controls and Procedures.

Under the direction of our general partner's Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of September 30, 2016 and (ii) except as discussed below, no change in internal control over financial reporting occurred during the quarter ended September 30, 2016, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

As disclosed in our report on Form 10-Q for the period ended June 30, 2016, we previously 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"). Subsequent to June 30, 2016, we implemented additional measures which remediated the material weakness. These additional measures included enhancements to our documented execution of the review and evaluation of our reporting requirements under Rule 3-10. Based on these additional measures, we consider the material weakness to be remediated as of September 30, 2016.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

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SIGNATURES

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



	Summit Midstream Partners, LP
	(Registrant)

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

November 7, 2016	/s/ Matthew S. Harrison
	Matthew S. Harrison, Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)