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

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2017

or

[ ] 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 ofincorporation 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)
Not applicable (Former name or former address, if changed since last report)

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth 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
Emerging growth company o

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

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

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

Class	As of July 31, 2017
Common Units	73,058,946 units
General Partner Units	1,490,999 units

TABLE OF CONTENTS

Commonly Used or Defined Terms		ii
PART I	FINANCIAL INFORMATION	1
Item 1.	Financial Statements.	1
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016	1
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016	2
	Unaudited Condensed Consolidated Statements of Partners' Capital for the six months ended June 30, 2017 and 2016	3
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017 and 2016	5
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	54
Item 4.	Controls and Procedures.	55
PART II	OTHER INFORMATION	55
Item 1.	Legal Proceedings.	55
Item 1A.	Risk Factors.	55
Item 6.	Exhibits.	55

i

COMMONLY USED OR DEFINED TERMS

2014 SRS	the Partnership's automatic shelf registration statement of well-known seasoned issuers initially filed with the SEC in July 2014 and amended in February 2017 which registered an indeterminate amount of common units, debt securities and guarantees
2016 Drop Down	the Partnership's March 3, 2016 acquisition of substantially all of (i) the issued and outstanding membership interests in Summit Utica, Meadowlark Midstream and Tioga Midstream and (ii) SMP Holdings’ 40% ownership interest in Ohio Gathering from SMP Holdings
2016 SRS	the Partnership's shelf registration statement declared effective in November 2016 which registered up to $1.5 billion of equity and debt securities in primary offerings and 36,701,230 common units beneficially owned by Summit Investments and affiliates of the Sponsor
2017 SRS	the Partnership's automatic shelf registration statement of well-known seasoned issuers filed with the SEC in July 2017 which registered an indeterminate amount of common units, debt securities and guarantees
5.5% Senior Notes	Summit Holdings' and Finance Corp. 5.5% senior unsecured notes due August 2022
7.5% Senior Notes	Summit Holdings' and Finance Corp. 7.5% senior unsecured notes redeemed March 2017
5.75% Senior Notes	Summit Holdings' and Finance Corp. 5.75% senior unsecured notes due April 2025
AMI	area of mutual interest; AMIs require that any production from wells drilled by our customers within the AMI be shipped on and/or processed by our gathering systems
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
ASU	Accounting Standards Update
Bbl	one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons
Bcf	one billion cubic feet
Bcfe/d	the equivalent of one billion cubic feet per day; generally calculated when liquids are converted into gas; determined using a ratio of six thousand cubic feet of natural gas to one barrel of liquids
Bison Midstream	Bison Midstream, LLC
Board of Directors	the board of directors of our General Partner
condensate	a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
Deferred Purchase Price Obligation	the deferred payment liability recognized in connection with the 2016 Drop Down
DFW Midstream	DFW Midstream Services LLC
DJ Basin	Denver-Julesburg Basin
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
Energy Capital Partners	Energy Capital Partners II, LLC and its parallel and co-investment funds; also known as the Sponsor
Epping	Epping Transmission Company, LLC
EPU	earnings or loss per unit
FASB	Financial Accounting Standards Board

ii

Finance Corp.	Summit Midstream Finance Corp.
GAAP	accounting principles generally accepted in the United States of America
General Partner	Summit Midstream GP, LLC
Grand River	Grand River Gathering, LLC
IDR	incentive distribution rights
IPO	initial public offering
LIBOR	London Interbank Offered Rate
Mbbl	one thousand barrels
Mbbl/d	one thousand barrels per day
Mcf	one thousand cubic feet
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Meadowlark Midstream	Meadowlark Midstream Company, LLC
MMcf	one million cubic feet
MMcf/d	one million cubic feet per day
Mountaineer Midstream	Mountaineer Midstream gathering system
MVC	minimum volume commitment
NGL	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
Niobrara G&P	Niobrara Gathering and Processing system
OCC	Ohio Condensate Company, L.L.C.
OGC	Ohio Gathering Company, L.L.C.
Ohio Gathering	Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C.
OpCo	Summit Midstream OpCo, LP
play	a proven geological formation that contains commercial amounts of hydrocarbons
Polar and Divide	the Polar and Divide system; collectively Polar Midstream and Epping
Polar Midstream	Polar Midstream, LLC
produced water	water from underground geologic formations that is a by-product of natural gas and crude oil production
Red Rock Gathering	Red Rock Gathering Company, LLC
Remaining Consideration	management's estimate of the consideration to be paid to SMP Holdings in 2020 in connection with the 2016 Drop Down, the present value of which is reflected on our balance sheets as the Deferred Purchase Price Obligation
Revolving Credit Facility	the Third Amended and Restated Credit Agreement dated as of May 26, 2017
SEC	Securities and Exchange Commission
segment adjusted EBITDA	total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) unit-based and noncash compensation, (vi) the change in the Deferred Purchase Price Obligation fair value, (vii) early extinguishment of debt expense, (viii) impairments and (ix) 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 its MVC for the applicable period

iii

SMLP	Summit Midstream Partners, LP
SMLP LTIP	SMLP Long-Term Incentive Plan
SMP Holdings	Summit Midstream Partners Holdings, LLC
Sponsor	Energy Capital Partners II, LLC and its parallel and co-investment funds; also known as Energy Capital Partners
Summit Holdings	Summit Midstream Holdings, LLC
Summit Investments	Summit Midstream Partners, LLC
Summit Marketing	Summit Midstream Marketing, LLC
Summit Permian	Summit Midstream Permian, LLC
Summit Utica	Summit Midstream Utica, LLC
the Company	Summit Midstream Partners, LLC and its subsidiaries
the Partnership	Summit Midstream Partners, LP and its subsidiaries
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
Tioga Midstream	Tioga Midstream, LLC
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

iv

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2017		December 31, 2016
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	2,588	$	7,428
Accounts receivable	55,837		97,364
Other current assets	2,264		4,309
Total current assets	60,689		109,101
Property, plant and equipment, net	1,859,953		1,853,671
Intangible assets, net	402,020		421,452
Goodwill	16,211		16,211
Investment in equity method investees	701,020		707,415
Other noncurrent assets	14,457		7,329
Total assets	$	3,054,350	$	3,115,179
Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	10,327	$	16,251
Accrued expenses	8,278		11,389
Due to affiliate	470		258
Deferred revenue	4,745		—
Ad valorem taxes payable	7,295		10,588
Accrued interest	17,015		17,483
Accrued environmental remediation	6,183		4,301
Other current liabilities	6,305		11,471
Total current liabilities	60,618		71,741
Long-term debt	1,280,645		1,240,301
Deferred Purchase Price Obligation	579,106		563,281
Deferred revenue	13,049		57,465
Noncurrent accrued environmental remediation	2,346		5,152
Other noncurrent liabilities	7,687		7,566
Total liabilities	1,943,451		1,945,506
Commitments and contingencies (Note 15)
Common limited partner capital (73,059 units issued and outstanding at June 30, 2017 and 72,111 units issued and outstanding at December 31, 2016)	1,071,244		1,129,132
General Partner interests (1,491 units issued and outstanding at June 30, 2017 and 1,471 units issued and outstanding at December 31, 2016)	28,217		29,294
Noncontrolling interest	11,438		11,247
Total partners' capital	1,110,899		1,169,673
Total liabilities and partners' capital	$	3,054,350	$	3,115,179

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

1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	84,801		$	76,187		$	202,814		$	154,287
Natural gas, NGLs and condensate sales	10,595			8,581			21,715			16,169
Other revenues	6,396			4,867			13,068			9,750
Total revenues	101,792			89,635			237,597			180,206
Costs and expenses:
Cost of natural gas and NGLs	9,099			6,864			18,151			13,154
Operation and maintenance	24,016			23,410			47,708			49,252
General and administrative	12,949			12,876			27,081			25,755
Depreciation and amortization	28,688			27,963			57,257			55,691
Transaction costs	119			122			119			1,296
Loss on asset sales, net	67			74			70			11
Long-lived asset impairment	3			569			287			569
Total costs and expenses	74,941			71,878			150,673			145,728
Other income	64			19			135			41
Interest expense	(17,553		)	(16,035		)	(34,269		)	(31,917		)
Early extinguishment of debt	—			—			(22,020		)	—
Deferred Purchase Price Obligation	5,058			(17,465		)	(15,825		)	(24,928		)
Income (loss) before income taxes and loss from equity method investees	14,420			(15,724		)	14,945			(22,326		)
Income tax benefit (expense)	211			(360		)	(241		)	(283		)
Loss from equity method investees	(3,385		)	(34,471		)	(4,041		)	(31,611		)
Net income (loss)	$	11,246		$	(50,555	)	$	10,663		$	(54,220	)
Less:
Net income attributable to Summit Investments	—			—			—			2,745
Net income (loss) attributable to noncontrolling interest	89			(268		)	191			(224		)
Net income (loss) attributable to SMLP	11,157			(50,287		)	10,472			(56,741		)
Less net income and IDRs attributable to General Partner	2,351			935			4,443			2,746
Net income (loss) attributable to limited partners	$	8,806		$	(51,222	)	$	6,029		$	(59,487	)
Earnings (loss) per limited partner unit:
Common unit – basic	$	0.12		$	(0.77	)	$	0.08		$	(0.89	)
Common unit – diluted	$	0.12		$	(0.77	)	$	0.08		$	(0.89	)
Weighted-average limited partner units outstanding:
Common unit – basic	72,532			66,587			72,341			66,540
Common unit – diluted	72,842			66,587			72,708			66,540

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

2

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

	Partners' capital									Noncontrolling interest			Summit Investments' equity in contributed subsidiaries
	Limited partners						General Partner
	Common			Subordinated												Total
	(In thousands)
Partners' capital, January 1, 2016	$	744,977		$	213,631		$	25,634		$	—		$	763,057		$	1,747,299
Net (loss) income	(60,527		)	1,040			2,746			(224		)	2,745			(54,220		)
Distributions to unitholders	(62,475		)	(14,034		)	(5,511		)	—			—			(82,020		)
Unit-based compensation	3,665			—			—			—			—			3,665
Tax withholdings on vested SMLP LTIP awards	(796		)	—			—			—			—			(796		)
Subordinated units conversion	200,637			(200,637		)	—			—			—			—
Purchase of 2016 Drop Down Assets	—			—			—			—			(866,858		)	(866,858		)
Establishment of noncontrolling interest	—			—			—			11,261			(11,261		)	—
Distribution of debt related to Carve-Out Financial Statements of Summit Investments	—			—			—			—			342,926			342,926
Excess of acquired carrying value over consideration paid for 2016 Drop Down Assets	243,044			—			4,953			—			(247,997		)	—
Cash advance from Summit Investments to contributed subsidiaries, net	—			—			—			—			12,214			12,214
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			—			—			—			4,821			4,821
Capitalized interest allocated from Summit Investments to contributed subsidiaries	—			—			—			—			223			223
Class B membership interest noncash compensation	155			—			—			—			130			285
Partners' capital, June 30, 2016	$	1,068,680		$	—		$	27,822		$	11,037		$	—		$	1,107,539

3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)

	Partners' capital						Noncontrolling interest
	Common limited partners			General Partner					Total
	(In thousands)
Partners' capital, January 1, 2017	$	1,129,132		$	29,294		$	11,247	$	1,169,673
Net income	6,029			4,443			191		10,663
Distributions to unitholders	(83,044		)	(5,985		)	—		(89,029		)
Unit-based compensation	3,919			—			—		3,919
Tax withholdings on vested SMLP LTIP awards	(2,051		)	—			—		(2,051		)
ATM Program issuances, net of costs	17,259			—			—		17,259
Contribution from General Partner	—			465			—		465
Partners' capital, June 30, 2017	$	1,071,244		$	28,217		$	11,438	$	1,110,899

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

4

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six months ended June 30,
	2017			2016
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	10,663		$	(54,220	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	56,955			55,957
Amortization of debt issuance costs	2,072			1,947
Deferred Purchase Price Obligation	15,825			24,928
Unit-based and noncash compensation	3,999			3,950
Loss from equity method investees	4,041			31,611
Distributions from equity method investees	18,003			24,181
Loss on asset sales, net	70			11
Long-lived asset impairment	287			569
Early extinguishment of debt	22,020			—
Write-off of debt issuance costs	302			—
Changes in operating assets and liabilities:
Accounts receivable	41,527			41,276
Trade accounts payable	(4,372		)	1,447
Accrued expenses	(3,111		)	1,008
Due from (to) affiliate	212			(966		)
Deferred revenue	(39,671		)	2,033
Ad valorem taxes payable	(3,293		)	(2,613		)
Accrued interest	(468		)	—
Accrued environmental remediation, net	(924		)	(1,752		)
Other, net	(2,796		)	2,133
Net cash provided by operating activities	121,341			131,500
Cash flows from investing activities:
Capital expenditures	(45,912		)	(91,372		)
Contributions to equity method investees	(15,649		)	(15,645		)
Acquisitions of gathering systems from affiliate	—			(359,431		)
Other, net	(521		)	(435		)
Net cash used in investing activities	(62,082		)	(466,883		)

5

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Six months ended June 30,
	2017			2016
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	(89,029		)	(82,020		)
Borrowings under Revolving Credit Facility	112,500			439,300
Repayments under Revolving Credit Facility	(269,500		)	(50,300		)
Debt issuance costs	(15,613		)	(2,766		)
Payment of redemption and call premiums on senior notes	(17,913		)	—
Proceeds from ATM Program issuances, net of costs	17,259			—
Contribution from General Partner	465			—
Cash advance from Summit Investments to contributed subsidiaries, net	—			12,214
Expenses paid by Summit Investments on behalf of contributed subsidiaries	—			4,821
Issuance of senior notes	500,000			—
Tender and redemption of senior notes	(300,000		)	—
Other, net	(2,268		)	(916		)
Net cash (used in) provided by financing activities	(64,099		)	320,333
Net change in cash and cash equivalents	(4,840		)	(15,050		)
Cash and cash equivalents, beginning of period	7,428			21,793
Cash and cash equivalents, end of period	$	2,588		$	6,743
Supplemental cash flow disclosures:
Cash interest paid	$	33,382		$	31,464
Less capitalized interest	918			1,779
Interest paid (net of capitalized interest)	$	32,464		$	29,685
Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	6,869		$	14,322
Issuance of Deferred Purchase Price Obligation to affiliate to partially fund the 2016 Drop Down	—			507,427
Excess of acquired carrying value over consideration paid and recognized for 2016 Drop Down Assets	—			247,997
Distribution of debt related to Carve-Out Financial Statements of Summit Investments	—			342,926
Capitalized interest allocated to contributed subsidiaries from Summit Investments	—			223

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

6

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

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

The General Partner, a Delaware limited liability company, manages our operations and activities. Summit Investments, a Delaware limited liability company, is the ultimate owner of our General Partner and has the right to appoint the entire Board of Directors. Summit Investments is controlled by Energy Capital Partners. As of June 30, 2017, a subsidiary of Energy Capital Partners directly owned 5,915,827 SMLP common units.

In addition to its approximate 2% general partner interest in SMLP (including the IDRs in respect of SMLP), Summit Investments has indirect ownership interests in our common units. As of June 30, 2017, Summit Investments beneficially owned 25,854,581 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.

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

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

• 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;

• Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; and

• Summit Permian, an associated natural gas gathering and processing system under development in the northern Delaware Basin in southeastern New Mexico.

7

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

Summit Marketing (formerly known as Summit Midstream OpCo GP, LLC), a Delaware limited liability company and a wholly owned subsidiary of Summit Holdings, manages OpCo, a Delaware limited liability partnership, and provides natural gas and crude oil marketing services in and around our gathering systems.

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

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. Comprehensive income or loss is the same as net income or loss for all periods presented. The financial position, results of operations and cash flows of acquired drop down assets, liabilities, expenses or entities that were carved out of entities held by Summit Investments and included herein have been derived from the accounting records of the respective Summit Investments' subsidiary on a carve-out basis.

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

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments, including normal recurring adjustments, which are necessary to fairly present the unaudited condensed consolidated balance sheet as of June 30, 2017, the unaudited condensed consolidated statements of operations for the three- and six- month periods ended June 30, 2017 and 2016 and the unaudited condensed consolidated statements of partners' capital and cash flows for the six-month periods ended June 30, 2017 and 2016. The balance sheet at December 31, 2016 included herein was derived from our audited financial statements, but does not include all disclosures required by GAAP. 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, 2016, as filed with the SEC on February 27, 2017 (the "2016 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

There have been no changes to our significant accounting policies since December 31, 2016.

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

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

• 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 statements of cash flows. ASU 2016-09 is effective for public companies

8

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. We adopted the provisions of ASU 2016-09 effective January 1, 2017. The adoption of this standard had no impact on our consolidated financial statements.

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. ASU 2014-09 is effective for fiscal years and interim periods within those years, beginning after December 15, 2017 and allows for early adoption. We expect to adopt the provisions of ASU 2014-09 effective January 1, 2018 using the modified retrospective method.

We have substantially completed our review of our existing contracts under the new guidance. However, we are still assessing the financial statement impact of adoption for certain items discussed below. For contracts where we perform gathering services and earn a per-unit fee which is recognized at a point in time, revenue will be recognized over time as the service is performed, which is expected to accelerate the recognition of revenue by an immaterial amount. In addition, our contracts generally contain forms of what will be considered variable consideration, which will likely be constrained as the volumes are susceptible to factors outside of our control and influence. However, we will be billing amounts that correspond directly to the value transferred such that the resulting revenue recognized will be similar to current GAAP. We are continuing to evaluate our MVCs and contributions in aid of construction and cannot currently fully conclude on the impact of adoption. We are working with an industry group to develop our position on certain implementation matters. We anticipate that we will be able to complete our assessment of the impact of adoption by the end of the third quarter of 2017.

• 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.

• 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.

3. SEGMENT INFORMATION

We evaluate our business operations each reporting period to determine whether any of our gathering system operating segments in which we internally report financial information are considered significant and would require

9

us to separately disclose certain segment financial information in our external reporting. As a result of our evaluation for the three-months ended June 30, 2017, we determined that both the Summit Utica natural gas gathering system and the Ohio Gathering natural gas gathering system, each previously reported within the Utica Shale reportable segment, were and are expected to continue to be significant operating segments. As such, we are modifying our current segments such that the Utica Shale reportable segment includes the Summit Utica gathering system and the Ohio Gathering reportable segment includes our ownership interest in OGC and OCC. For the three- and six-months ended June 30, 2017, we have disclosed the required segment information for Summit Utica and Ohio Gathering and the periods prior to January 1, 2017 have been recast to reflect this change.

As of June 30, 2017, our reportable segments are:

• the Utica Shale, which is served by Summit Utica;

• Ohio Gathering, which includes our ownership interest in OGC and OCC;

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

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

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

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

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

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

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

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Assets by reportable segment follow.

	June 30, 2017			December 31, 2016
	(In thousands)
Assets:
Utica Shale	$	213,030		$	199,392
Ohio Gathering	701,020			707,415
Williston Basin	699,361			724,084
Piceance/DJ Basins	799,058			843,440
Barnett Shale	395,266			404,314
Marcellus Shale	220,899			224,709
Total reportable segment assets	3,028,634			3,103,354
Corporate and other	25,940			12,294
Eliminations	(224		)	(469		)
Total assets	$	3,054,350		$	3,115,179

Revenues by reportable segment follow.

	Three months ended June 30,					Six months ended June 30,
	2017			2016		2017			2016
	(In thousands)
Revenues (1):
Utica Shale	$	10,456		$	5,403	$	19,252		$	9,686
Williston Basin	29,114			27,507		95,999			57,517
Piceance/DJ Basins	33,763			29,411		68,571			58,402
Barnett Shale	20,904			20,856		38,646			41,257
Marcellus Shale	7,365			6,458		14,269			13,344
Total reportable segments revenue	101,602			89,635		236,737			180,206
Corporate and other	1,362			—		3,148			—
Eliminations	(1,172		)	—		(2,288		)	—
Total revenues	$	101,792		$	89,635	$	237,597		$	180,206

__________

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

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

	Three months ended June 30,			Six months ended June 30,
	2017		2016	2017		2016
Percentage of total revenues (1)(2):
Counterparty A - Piceance Basin	10	%	*	*		*
Counterparty B - Barnett Shale	11	%	*	*		*
Counterparty C - Utica Shale	10	%	*	*		*
Counterparty D - Williston Basin	*		*	21	%	*

__________

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

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

* Less than 10%

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

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	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
Depreciation and amortization (1):
Utica Shale	$	1,748	$	952	$	3,395	$	1,796
Williston Basin	8,385		8,410		16,766		16,767
Piceance/DJ Basins	12,225		12,297		24,436		24,570
Barnett Shale (2)	3,762		4,057		7,524		8,113
Marcellus Shale	2,263		2,222		4,526		4,441
Total reportable segment depreciation and amortization	28,383		27,938		56,647		55,687
Corporate and other	154		154		308		270
Total depreciation and amortization	$	28,537	$	28,092	$	56,955	$	55,957

__________

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

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

Cash paid for capital expenditures by reportable segment follow.

	Six months ended June 30,
	2017			2016
	(In thousands)
Cash paid for capital expenditures (1):
Utica Shale	$	16,473		$	54,064
Williston Basin	11,085			21,919
Piceance/DJ Basins	11,934			10,633
Barnett Shale	(399		)	2,109
Marcellus Shale	407			2,135
Total reportable segment capital expenditures	39,500			90,860
Corporate and other	6,412			512
Total cash paid for capital expenditures	$	45,912		$	91,372

__________

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

During the six months ended June 30, 2017, Corporate and other primarily includes cash paid for capital expenditures of approximately $5.0 million for Summit Permian.

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

For the purpose of evaluating segment performance, we exclude the effect of Corporate and other revenues and expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), natural gas and crude oil marketing services, transaction costs, interest expense, change in the Deferred Purchase Price Obligation fair value, early extinguishment of debt expense and income tax expense or benefit from segment adjusted EBITDA.

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Segment adjusted EBITDA by reportable segment follows.

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
Reportable segment adjusted EBITDA:
Utica Shale	$	9,533	$	4,727	$	17,445	$	7,916
Ohio Gathering	9,606		12,725		18,679		25,113
Williston Basin	17,155		19,209		34,964		38,929
Piceance/DJ Basins	27,274		26,231		56,248		51,046
Barnett Shale	12,998		13,913		25,086		27,990
Marcellus Shale	5,446		4,807		11,093		9,408
Total of reportable segments’ measures of profit or loss	$	82,012	$	81,612	$	163,515	$	160,402

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

	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(In thousands)
Reconciliation of income (loss) before income taxes and loss from equity method investees to total of reportable segments' measures of profit or loss:
Income (loss) before income taxes and loss from equity method investees	$	14,420		$	(15,724	)	$	14,945		$	(22,326	)
Add:
Corporate and other	9,435			9,247			19,528			18,006
Interest expense	17,553			16,035			34,269			31,917
Early extinguishment of debt	—			—			22,020			—
Deferred Purchase Price Obligation	(5,058		)	17,465			15,825			24,928
Depreciation and amortization	28,537			28,092			56,955			55,957
Proportional adjusted EBITDA for equity method investees	9,606			12,725			18,679			25,113
Adjustments related to MVC shortfall payments	5,578			11,135			(23,062		)	22,277
Unit-based and noncash compensation	1,871			1,994			3,999			3,950
Loss on asset sales, net	67			74			70			11
Long-lived asset impairment	3			569			287			569
Total of reportable segments' measures of profit or loss	$	82,012		$	81,612		$	163,515		$	160,402

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

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Adjustments related to MVC shortfall payments by reportable segment follow.

	Three months ended June 30, 2017
	Williston Basin		Piceance/DJ Basins			Barnett Shale			Total
	(In thousands)
Adjustments related to MVC shortfall payments:
Net change in deferred revenue for MVC shortfall payments	$	—	$	(1,186	)	$	—		$	(1,186	)
Expected MVC shortfall payments	1,982		6,522			(1,740		)	6,764
Total adjustments related to MVC shortfall payments	$	1,982	$	5,336		$	(1,740	)	$	5,578

	Three months ended June 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	$	—	$	1,237	$	(677	)	$	560
Expected MVC shortfall payments	4,261		6,219		95			10,575
Total adjustments related to MVC shortfall payments	$	4,261	$	7,456	$	(582	)	$	11,135

	Six months ended June 30, 2017
	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	$	(37,693	)	$	(1,978	)	$	—		$	(39,671	)
Expected MVC shortfall payments	3,964			13,067			(422		)	16,609
Total adjustments related to MVC shortfall payments	$	(33,729	)	$	11,089		$	(422	)	$	(23,062	)

	Six months ended June 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	$	2,475	$	(677	)	$	2,033
Expected MVC shortfall payments	7,562		12,498		184			20,244
Total adjustments related to MVC shortfall payments	$	7,797	$	14,973	$	(493	)	$	22,277

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4. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	June 30, 2017		December 31, 2016
	(In thousands)
Gathering and processing systems and related equipment	$	2,067,428	$	2,026,363
Construction in progress	40,332		39,954
Land and line fill	11,735		11,442
Other	35,083		35,227
Total	2,154,578		2,112,986
Less accumulated depreciation	294,625		259,315
Property, plant and equipment, net	$	1,859,953	$	1,853,671

Depreciation expense and capitalized interest follow.

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
Depreciation expense	$	18,607	$	17,595	$	37,098	$	34,966
Capitalized interest	450		1,063		918		1,779

5. AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT

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

	June 30, 2017
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(11,572	)	$	12,623
Contract intangibles	12.5	426,464		(163,570		)	262,894
Rights-of-way	26.1	154,519		(28,016		)	126,503
Total intangible assets		$	605,178	$	(203,158	)	$	402,020
Unfavorable gas gathering contract	10.0	$	10,962	$	(7,995	)	$	2,967

	December 31, 2016
	Useful lives (In years)	Gross carrying amount		Accumulated amortization			Net
		(Dollars in thousands)
Favorable gas gathering contracts	18.7	$	24,195	$	(10,795	)	$	13,400
Contract intangibles	12.5	426,464		(146,468		)	279,996
Rights-of-way	26.1	153,015		(24,959		)	128,056
Total intangible assets		$	603,674	$	(182,222	)	$	421,452
Unfavorable gas gathering contract	10.0	$	10,962	$	(6,916	)	$	4,046

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We recognized amortization expense in other revenues as follows:

	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(388	)	$	(317	)	$	(777	)	$	(655	)
Amortization expense – unfavorable gas gathering contract	539			188			1,079			389

We recognized amortization expense in costs and expenses as follows:

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
Amortization expense – contract intangibles	$	8,551	$	8,854	$	17,102	$	17,708
Amortization expense – rights-of-way	1,530		1,514		3,057		3,017

The estimated aggregate annual amortization expected to be recognized for the remainder of 2017 and each of the four succeeding fiscal years follows.

	Intangible assets		Unfavorable gas gathering contract
	(In thousands)
2017	$	21,196	$	1,079
2018	41,373		1,888
2019	41,204		—
2020	43,453		—
2021	41,679		—

6. GOODWILL

We evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. There have been no impairments of goodwill during the three- and six-months ended June 30, 2017.

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 2016 Annual Report. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

7. EQUITY METHOD INVESTMENTS

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

In June 2017 and June 2016, an impairment loss was recognized by Ohio Gathering. 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 2017 and 2016 because the information was available to us. We recorded our 40% share of the impairment loss, or $3.5 million in June 2017 and $37.8 million in June 2016, in loss from equity method investees in the unaudited condensed consolidated statements of operations.

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

Investment in equity method investees, June 30, 2017	$	701,020
June cash distribution	3,128
June cash contribution	(3,484		)
Impairment loss	3,474
Basis difference	(136,860		)
Investment in equity method investees, net of basis difference, May 31, 2017	$	567,278

Summarized statements of operations information for OGC and OCC follows (amounts represent 100% of investee financial information). Results include asset impairments of $8.7 million for the three- and six-month periods ending June 30, 2017 and $94.4 million for the three- and six-month periods ending June 30, 2016.

	Three months ended May 31, 2017					Three months ended May 31, 2016
	OGC			OCC		OGC		OCC
	(In thousands)
Total revenues	$	31,083		$	2,004	$	38,444	$	5,417
Total operating expenses	33,221			1,836		22,572		98,748
Net (loss) income	(139		)	23		15,868		(93,701		)

	Six months ended May 31, 2017					Six months ended May 31, 2016
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	68,158	$	4,057		$	76,243	$	10,615
Total operating expenses	60,326		4,309			45,105		103,307
Net income (loss)	7,834		(1,192		)	31,137		(93,245		)

8. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Total current
	(In thousands)
Current deferred revenue, January 1, 2017	$	—	$	—	$	—
Additions	—		12,602		12,602
Less revenue recognized	—		7,857		7,857
Current deferred revenue, June 30, 2017	$	—	$	4,745	$	4,745

A rollforward of noncurrent deferred revenue follows.

	Williston Basin		Piceance/DJ Basins		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2017	$	37,693	$	19,772	$	57,465
Less revenue recognized	37,693		1,978		39,671
Less reclassification to current deferred revenue	—		4,745		4,745
Noncurrent deferred revenue, June 30, 2017	$	—	$	13,049	$	13,049

As of June 30, 2017, accounts receivable included $7.6 million of total shortfall payment billings, of which none related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods.

17

During the first quarter of 2017, we amended an agreement with one of our key customers in the Williston Basin segment. As a result, we recognized previously deferred revenue of $37.7 million as gathering services and related fees during the first quarter of 2017.

9. DEBT

Debt consisted of the following:

	June 30, 2017			December 31, 2016
	(In thousands)
Summit Holdings variable rate senior secured Revolving Credit Facility (3.73% at June 30, 2017 and 3.27% at December 31, 2016) due May 2022	$	491,000		$	648,000
Summit Holdings 5.5% senior unsecured notes due August 2022	300,000			300,000
Less unamortized debt issuance costs (1)	(3,180		)	(3,516		)
Summit Holdings 5.75% senior unsecured notes due April 2025	500,000			—
Less unamortized debt issuance costs (1)	(7,175		)	—
Summit Holdings 7.5% senior unsecured notes redeemed March 2017 (2)	—			300,000
Less unamortized debt issuance costs (1) (2)	—			(4,183		)
Total long-term debt	$	1,280,645		$	1,240,301

__________

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

(2) Debt was extinguished following the 5.75% Senior Notes offering in February 2017. In conjunction with the early debt extinguishment, the remaining unamortized debt issuance costs were written off.

The aggregate amount of debt maturing to be recognized for the remainder of 2017 and each of the four succeeding fiscal years follow (in thousands):

2017	$	—
2018	—
2019	—
2020	—
2021	—
Thereafter	1,291,000
Total long-term debt	$	1,291,000

Revolving Credit Facility. Summit Holdings has a senior secured revolving credit facility that allows for revolving loans, letters of credit and swingline loans. On May 26, 2017, Summit Holdings amended and restated its revolving credit facility with a third amended and restated credit agreement which: (i) maintained the revolving credit facility commitments of $1.25 billion, (ii) extended the maturity from November 2018 to May 2022, (iii) includes a $250.0 million accordion feature, (iv) maintained the same leverage-based pricing and commitment fee grid, (v) increased the maximum permitted total leverage ratio, as defined in the credit agreement, from 5.00 to 1.00 to 5.50 to 1.00 and (vi) includes a maximum permitted senior secured leverage ratio, as defined in the credit agreement, of 3.75 to 1.00.

Borrowings under the revolving credit facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 1.75% or the adjusted Eurodollar rate (as defined in the credit agreement) plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At June 30, 2017, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 3.73% and the unused portion of the Revolving Credit Facility totaled $759.0 million (subject to a commitment fee of 0.50%).

The revolving credit facility is secured by the membership interests of Summit Holdings and the membership interests of all the subsidiaries of Summit Holdings and by substantially all of the assets of Summit Holdings and its subsidiaries (subject to exclusions set forth in the credit agreement). It is guaranteed by SMLP and all of the subsidiaries of Summit Holdings other than the Specified Subsidiaries (as defined in the credit agreement). The credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature

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that, among other things, limit or restrict the ability (i) to incur additional debt; (ii) to make investments; (iii) to engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) to enter into swap agreements and power purchase agreements; (v) to enter into leases that would cumulatively obligate payments in excess of $50.0 million over any 12-month period; and (vi) of Summit Holdings to make distributions, with certain exceptions, including the distribution of Available Cash (as defined in the SMLP partnership agreement) if no default or event of default then exists or would result therefrom and Summit Holdings is in pro forma compliance with its financial covenants. The credit agreement also contains an affirmative covenant that could require our Non-Guarantor Subsidiaries (OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream) to become guarantor subsidiaries in certain circumstances. In addition, the revolving credit facility requires Summit Holdings to maintain (i) a ratio of consolidated trailing 12-month earnings before interest, income taxes, depreciation and amortization ("EBITDA") to net interest expense of not less than 2.5 to 1.0 as defined in the credit agreement, (ii) a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.50 to 1.00 and, (iii) a ratio of first lien net indebtedness to consolidated trailing 12-month EBITDA of not more than 3.75 to 1.00.

As a result of the amendment, SMLP incurred approximately $8.1 million of debt issuance costs. As of June 30, 2017, we had $11.7 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in noncurrent assets on the unaudited condensed consolidated balance sheet.

As of June 30, 2017, we were in compliance with the Revolving Credit Facility's covenants. There were no defaults or events of default during the six months ended June 30, 2017.

Senior Notes. In June 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 7.5% senior unsecured notes (the "7.5% Senior Notes"). In July 2014, the Co-Issuers co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "5.5% Senior Notes" and, together with the 5.75% Senior Notes (defined below, the “Senior Notes”).

On February 8, 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes (the "5.75% Senior Notes") as described below. Concurrent with the 5.75% Senior Notes offering, we made a tender offer to purchase all the outstanding 7.5% Senior Notes. The tender offer expired on February 14, 2017 and resulted in approximately $276.9 million of our 7.5% Senior Notes being validly tendered and retired. On February 16, 2017, we issued a notice of redemption for the remaining 7.5% Senior Notes. The remaining $23.1 million of 7.5% Senior Notes were redeemed on March 18, 2017 (the "redemption date"), with payment made on March 20, 2017. References to the “Senior Notes,” when used for dates or periods ended on or after the date of issuance of the 5.75% Senior Notes but before the redemption date, refer collectively to 5.5% Senior Notes, 7.5% Senior Notes and 5.75% Senior Notes. References to the "Senior Notes," when used for dates or periods ended on or prior to the date of issuance of the 5.75% Senior Notes, refer collectively to 5.5% Senior Notes and 7.5% Senior Notes. References to the "Senior Notes," when used for dates or periods that ended after the redemption date, refer collectively to the 5.5% Senior Notes and the 5.75% Senior Notes. In conjunction with the tender offer and mandatory redemption of the 7.5% Senior Notes, we paid redemption and call premiums totaling $17.9 million. These costs, as well as $4.1 million of unamortized debt issuance costs, are presented on our unaudited condensed consolidated statement of operations as early extinguishment of debt.

On June 15, 2017, we executed a supplemental indenture and an amendment to our Revolving Credit Facility to add a newly formed entity, Summit Permian, as a guarantor. As a result, Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream, Summit Marketing and Summit Permian (collectively the "Guarantor Subsidiaries") and SMLP fully and unconditionally and jointly and severally guarantee the 5.5% Senior Notes and the 5.75% Senior Notes. The Senior Notes are not guaranteed by OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream (collectively, the "Non-Guarantor Subsidiaries"). 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. At no time have the Senior Notes been guaranteed by the Co-Issuers.

5.75%Senior Notes. In February 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025. Interest on the 5.75% Senior Notes will be paid semi-annually in cash in arrears on April 15 and October 15 of each year, beginning on October 15, 2017. The 5.75% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.75% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

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At any time prior to April 15, 2020, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.750% of the principal amount of the 5.75% Senior Notes, plus accrued and unpaid interest, if any, but not including, the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after April 15, 2020, the Co-Issuers may redeem all or part of the 5.75% Senior Notes at a redemption price of 104.313% (with the redemption premium declining ratably each year to 100.000% on and after April 15, 2023), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs of $7.5 million are being amortized over the life of the senior notes.

The 5.75% Senior Notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate.

The 5.75% Senior Notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.75% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.75% Senior Notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $75.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.75% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.75% Senior Notes may declare all the 5.75% Senior Notes to be due and payable immediately.

As of and during the six months ended June 30, 2017, we were in compliance with the covenants governing our Senior Notes. There were no defaults or events of default during the six months ended June 30, 2017.

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

10. FINANCIAL INSTRUMENTS

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

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

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counterparties accounted for 46% of total accounts receivable at June 30, 2017, compared with 62% as of December 31, 2016.

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).

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

Level 3 liability, January 1, 2017	$	563,281
Change in fair value	15,825
Level 3 liability, June 30, 2017	$	579,106

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

	June 30, 2017				December 31, 2016
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings Revolving Credit Facility	$	491,000	$	491,000	$	648,000	$	648,000
Summit Holdings 5.5% Senior Notes ($300.0 million principal)	296,820		300,250		296,484		294,500
Summit Holdings 5.75% Senior Notes ($500.0 million principal)	492,825		504,167		—		—
Summit Holdings 7.5% Senior Notes ($300.0 million principal) (1)	—		—		295,817		316,000

__________

(1)  Debt was extinguished following the 5.75% Senior Notes offering in February 2017. In conjunction with the early debt extinguishment, the remaining unamortized debt issuance costs were written off.

The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to its floating interest rate. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of June 30, 2017 and December 31, 2016. 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 and General Partner units follows.

	Common	General Partner	Total
Units, January 1, 2017	72,111,121	1,471,187	73,582,308
Net units issued under SMLP LTIP	184,277	—	184,277
Units issued under ATM Program	763,548	—	763,548
General Partner 2% contribution	—	19,812	19,812
Units, June 30, 2017	73,058,946	1,490,999	74,549,945

Unit Offerings. In February 2017, we completed a secondary underwritten public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments pursuant to the 2016 SRS. We did not receive any proceeds from this offering.

At-the-market Program. In February 2017, we executed a new equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP

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common units having an aggregate offering price of up to $150.0 million (the "ATM Program"). These sales will be made (i) pursuant to the terms of the equity distribution agreement between us and the sales agents named therein and (ii) by means of ordinary brokers' transactions at market prices, in block transactions or as otherwise agreed between us and the sales agents. Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rules.

During the three months ended June 30, 2017, we sold 745,848 units under the ATM Program for aggregate gross proceeds of $17.3 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. During the six months ended June 30, 2017, we sold 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. Following the effectiveness of the new ATM registration statement and after taking into account the aggregate sales price of common units sold under the ATM Program through June 30, 2017, we have the capacity to issue additional common units under the ATM Program up to an aggregate $132.3 million.

In June 2017, our General Partner made a capital contribution to maintain its 2% general partner interest in SMLP.

Noncontrolling Interest. We have recorded Summit Investments' indirect retained ownership interest in OpCo and its subsidiaries as a noncontrolling interest in the unaudited condensed 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 that have been acquired by SMLP. The balance also reflects net income attributable to Summit Investments for the 2016 Drop Down Assets for the periods beginning on their respective acquisition dates by Summit Investments and ending on the date they were acquired by the Partnership. Net income or loss was attributed to Summit Investments for the 2016 Drop Down Assets for the period from January 1, 2016 to March 3, 2016. Although included in partners' capital, any net income or loss attributable to Summit Investments is excluded from the calculation of EPU.

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

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
Per-unit distributions to unitholders	$	0.575	$	0.575	$	1.150	$	1.150

On July 27, 2017, the Board of Directors of our General Partner declared a distribution of $0.575 per unit for the quarterly period ended June 30, 2017. This distribution, which totaled $45.0 million, will be paid on August 14, 2017 to unitholders of record at the close of business on August 7, 2017.

Incentive Distribution Rights.Our general partner also currently holds IDRs that entitle it to receive increasing percentage allocations, up to a maximum of 50%, of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the three and six months ended June 30 follow.

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
IDR payments	$	2,106	$	1,938	$	4,206	$	3,874

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

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12. EARNINGS PER UNIT

The following table details the components of EPU.

	Three months ended June 30,					Six months ended June 30,
	2017		2016			2017		2016
	(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Net income (loss) attributable to common units	$	8,806	$	(51,222	)	$	6,029	$	(59,487	)
Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	72,532		66,587			72,341		66,540
Effect of nonvested phantom units	310		—			367		—
Weighted-average common units outstanding – diluted	72,842		66,587			72,708		66,540
Earnings (loss) per limited partner unit:
Common unit – basic	$	0.12	$	(0.77	)	$	0.08	$	(0.89	)
Common unit – diluted	$	0.12	$	(0.77	)	$	0.08	$	(0.89	)
Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU	—		4			—		250

13. UNIT-BASED AND NONCASH COMPENSATION

SMLP Long-Term Incentive Plan. The SMLP LTIP provides for equity awards to eligible officers, employees, consultants and directors of our General Partner and its affiliates. Items to note:

• In March 2017, we granted 366,181 phantom units and associated distribution equivalent rights to employees in connection with our annual incentive compensation award cycle. These awards had a grant date fair value of $22.50 and vest ratably over a three-year period.

• Also in March 2017, 184,277 phantom units vested.

• As of June 30, 2017, approximately 3.6 million common units remained available for future issuance under the SMLP LTIP.

14. RELATED-PARTY TRANSACTIONS

Acquisitions. For information on the 2016 Drop Down and its funding, see Notes 11 and 16 of the 2016 Annual Report.

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. The "Due to affiliate" line item on the consolidated balance sheet represents the payables to our General Partner for expenses incurred by it and paid on our behalf.

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

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
Operation and maintenance expense	$	6,731	$	6,623	$	13,612	$	13,372
General and administrative expense	7,895		7,679		16,190		15,457

Expenses Incurred by Summit Investments. Prior to the 2016 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 and is reflected in general and administrative expenses in the statements of operations.

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

In February 2017, SMP Holdings sold 4,000,000 common units representing limited partner interests in SMLP at a price to the public of $24.00 per common unit. Consistent with its obligations under our Partnership Agreement, SMLP paid all costs and expenses of the secondary offering (other than underwriting discounts and fees and expenses of counsel and advisors to SMP Holdings in the sale). SMLP did not receive any of the proceeds from the secondary offering.

15. COMMITMENTS AND CONTINGENCIES

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

	Three months ended June 30,				Six months ended June 30,
	2017		2016		2017		2016
	(In thousands)
Rent expense	$	923	$	745	$	1,802	$	1,361

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.

As described in detail in the 2016 Annual Report, in January 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, which was covered by Summit Investments' insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. Summit Investments exhausted the $25.0 million pollution liability policy in 2015. We submitted property and business interruption claim requests to the insurers and reached a settlement in January 2017. In connection therewith, we recognized $2.6 million of business interruption recoveries and $0.4 million of property recoveries.

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A rollforward of the aggregate accrued environmental remediation liabilities follows.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2017	$	9,453
Payments made	(924		)
Accrued environmental remediation, June 30, 2017	$	8,529

As of June 30, 2017, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to June 30, 2018. 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.

While we cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident, 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, SMLP acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets. These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin as well as ownership interests in a natural gas gathering system and a condensate stabilization facility, both located in the Utica Shale.

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

The Deferred Purchase Price Obligation will be equal to:

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

• less the Initial Payment;

• less all capital expenditures incurred for the 2016 Drop Down Assets between the 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, allocated interest expense and allocated income tax expense.

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

The present value of the Deferred Purchase Price Obligation will be reflected as a liability on our balance sheet until paid. As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets) was estimated to be $860.3 million and had a net present value of $507.4 million, using a discount rate of 13%. As of June 30, 2017, Remaining Consideration was estimated to be $793.3 million and the net present value, as recognized on the consolidated balance sheet, was $579.1 million, using a discount rate of 11.5%. Any subsequent changes to the estimated future payment obligation will be calculated using a discounted cash flow model with a commensurate risk-adjusted discount rate. Such changes and the impact on the liability due to the passage of time will be recorded as a change in the Deferred Purchase Price Obligation fair value on the consolidated statements of operations in the period of the change.

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

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

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

	Six months ended June 30, 2016
	(In thousands)
SMLP revenues	$	171,339
2016 Drop Down Assets revenues (1)	8,867
Combined revenues	$	180,206
SMLP net loss	$	(56,965	)
2016 Drop Down Assets net income (1)	2,745
Combined net loss	$	(54,220	)

__________

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

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

26

• 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.

Condensed Consolidating Balance Sheets. Balance sheets as of June 30, 2017 and December 31, 2016 follow.

	June 30, 2017
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	228	$	79	$	1,921	$	360	$	—		$	2,588
Accounts receivable	22		—		45,240		10,575		—			55,837
Other current assets	950		—		1,095		219		—			2,264
Due from affiliate	9,360		14,995		467,452		—		(491,807		)	—
Total current assets	10,560		15,074		515,708		11,154		(491,807		)	60,689
Property, plant and equipment, net	9,381		—		1,429,927		420,645		—			1,859,953
Intangible assets, net	—		—		377,216		24,804		—			402,020
Goodwill	—		—		16,211		—		—			16,211
Investment in equity method investees	—		—		—		701,020		—			701,020
Other noncurrent assets	2,628		11,674		155		—		—			14,457
Investment in subsidiaries	2,159,778		3,430,690		—		—		(5,590,468		)	—
Total assets	$	2,182,347	$	3,457,438	$	2,339,217	$	1,157,623	$	(6,082,275	)	$	3,054,350
Liabilities and Partners' Capital
Trade accounts payable	$	703	$	—	$	4,852	$	4,772	$	—		$	10,327
Accrued expenses	1,729		—		6,020		529		—			8,278
Due to affiliate	482,917		—		—		9,360		(491,807		)	470
Deferred revenue	—		—		4,745		—		—			4,745
Ad valorem taxes payable	—		—		6,870		425		—			7,295
Accrued interest	—		17,015		—		—		—			17,015
Accrued environmental remediation	—		—		—		6,183		—			6,183
Other current liabilities	3,275		—		2,643		387		—			6,305
Total current liabilities	488,624		17,015		25,130		21,656		(491,807		)	60,618
Long-term debt	—		1,280,645		—		—		—			1,280,645
Deferred Purchase Price Obligation	579,106		—		—		—		—			579,106
Deferred revenue	—		—		13,049		—		—			13,049
Noncurrent accrued environmental remediation	—		—		—		2,346		—			2,346
Other noncurrent liabilities	3,718		—		3,834		135					7,687
Total liabilities	1,071,448		1,297,660		42,013		24,137		(491,807		)	1,943,451
Total partners' capital	1,110,899		2,159,778		2,297,204		1,133,486		(5,590,468		)	1,110,899
Total liabilities and partners' capital	$	2,182,347	$	3,457,438	$	2,339,217	$	1,157,623	$	(6,082,275	)	$	3,054,350

27

	December 31, 2016
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	698	$	51	$	5,647	$	1,032	$	—		$	7,428
Accounts receivable	53		—		89,584		7,727		—			97,364
Other current assets	1,526		—		2,328		455		—			4,309
Due from affiliate	14,896		38,013		369,995		—		(422,904		)	—
Total current assets	17,173		38,064		467,554		9,214		(422,904		)	109,101
Property, plant and equipment, net	2,266		—		1,440,180		411,225		—			1,853,671
Intangible assets, net	—		—		396,930		24,522		—			421,452
Goodwill	—		—		16,211		—		—			16,211
Investment in equity method investees	—		—		—		707,415		—			707,415
Other noncurrent assets	1,993		5,198		138		—		—			7,329
Investment in subsidiaries	2,132,757		3,347,393		—		—		(5,480,150		)	—
Total assets	$	2,154,189	$	3,390,655	$	2,321,013	$	1,152,376	$	(5,903,054	)	$	3,115,179
Liabilities and Partners' Capital
Trade accounts payable	$	978	$	—	$	9,901	$	5,372	$	—		$	16,251
Accrued expenses	2,399		114		6,069		2,807		—			11,389
Due to affiliate	408,266		—		—		14,896		(422,904		)	258
Ad valorem taxes payable	16		—		9,717		855		—			10,588
Accrued interest	—		17,483		—		—		—			17,483
Accrued environmental remediation	—		—		—		4,301		—			4,301
Other current liabilities	6,718		—		3,798		955		—			11,471
Total current liabilities	418,377		17,597		29,485		29,186		(422,904		)	71,741
Long-term debt	—		1,240,301		—		—		—			1,240,301
Deferred Purchase Price Obligation	563,281		—		—		—		—			563,281
Deferred revenue	—		—		57,465		—		—			57,465
Noncurrent accrued environmental remediation	—		—		—		5,152		—			5,152
Other noncurrent liabilities	2,858		—		4,602		106		—			7,566
Total liabilities	984,516		1,257,898		91,552		34,444		(422,904		)	1,945,506
Total partners' capital	1,169,673		2,132,757		2,229,461		1,117,932		(5,480,150		)	1,169,673
Total liabilities and partners' capital	$	2,154,189	$	3,390,655	$	2,321,013	$	1,152,376	$	(5,903,054	)	$	3,115,179

28

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 six months ended June 30, 2017 and 2016 follow.

	Three months ended June 30, 2017
	SMLP		Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—	$	—		$	65,654	$	19,147		$	—		$	84,801
Natural gas, NGLs and condensate sales	—		—			10,407		188			—			10,595
Other revenues	—		—			5,880		516			—			6,396
Total revenues	—		—			81,941		19,851			—			101,792
Costs and expenses:
Cost of natural gas and NGLs	—		—			9,079		20			—			9,099
Operation and maintenance	—		—			20,917		3,099			—			24,016
General and administrative	—		—			10,544		2,405			—			12,949
Depreciation and amortization	154		—			24,624		3,910			—			28,688
Transaction costs	119		—			—		—			—			119
Loss on asset sales, net	—		—			65		2			—			67
Long-lived asset impairment	—		—			2		1			—			3
Total costs and expenses	273		—			65,231		9,437			—			74,941
Other income	64		—			—		—			—			64
Interest expense	—		(17,553		)	—		—			—			(17,553		)
Deferred Purchase Price Obligation	5,058		—			—		—			—			5,058
Income (loss) before income taxes and loss from equity method investees	4,849		(17,553		)	16,710		10,414			—			14,420
Income tax benefit	211		—			—		—			—			211
Loss from equity method investees	—		—			—		(3,385		)	—			(3,385		)
Equity in earnings of consolidated subsidiaries	6,186		23,739			—		—			(29,925		)	—
Net income	$	11,246	$	6,186		$	16,710	$	7,029		$	(29,925	)	$	11,246

29

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

30

	Six months ended June 30, 2017
	SMLP			Co-Issuers				Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—			$	166,336	$	36,478		$	—		$	202,814
Natural gas, NGLs and condensate sales	—			—				21,527		188			—			21,715
Other revenues	—			—				11,841		1,227			—			13,068
Total revenues	—			—				199,704		37,893			—			237,597
Costs and expenses:
Cost of natural gas and NGLs	—			—				18,128		23			—			18,151
Operation and maintenance	—			—				41,768		5,940			—			47,708
General and administrative	—			—				22,762		4,319			—			27,081
Depreciation and amortization	308			—				49,221		7,728			—			57,257
Transaction costs	119			—				—		—			—			119
Loss on asset sales, net	—			—			—	68		2			—			70
Long-lived asset impairment	—			—				2		285			—			287
Total costs and expenses	427			—				131,949		18,297			—			150,673
Other income	135			—				—		—			—			135
Interest expense	—			(34,269		)		—		—			—			(34,269		)
Early extinguishment of debt	—			(22,020		)		—		—			—			(22,020		)
Deferred Purchase Price Obligation	(15,825		)	—				—		—			—			(15,825		)
(Loss) income before income taxes and loss from equity method investees	(16,117		)	(56,289		)		67,755		19,596			—			14,945
Income tax expense	(241		)	—				—		—			—			(241		)
Loss from equity method investees	—			—				—		(4,041		)	—			(4,041		)
Equity in earnings of consolidated subsidiaries	27,021			83,310				—		—			(110,331		)	—
Net income	$	10,663		$	27,021			$	67,755	$	15,555		$	(110,331	)	$	10,663

31

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

32

Condensed Consolidating Statements of Cash Flows. Statements of cash flows for the six months ended June 30, 2017 and 2016 follow.

	Six months ended June 30, 2017
	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	$	424		$	(32,466	)	$	114,872		$	38,511		$	—		$	121,341
Cash flows from investing activities:
Capital expenditures	(6,412		)	—			(21,474		)	(18,026		)	—			(45,912		)
Contributions to equity method investees	—			—			—			(15,649		)	—			(15,649		)
Other, net	(521		)	—			—			—			—			(521		)
Advances to affiliates	5,536			23,020			(97,460		)	—			68,904			—
Net cash used in investing activities	(1,397		)	23,020			(118,934		)	(33,675		)	68,904			(62,082		)
Cash flows from financing activities:
Distributions to unitholders	(89,029		)	—			—			—			—			(89,029		)
Borrowings under Revolving Credit Facility	—			112,500			—			—			—			112,500
Repayments under Revolving Credit Facility	—			(269,500		)	—			—			—			(269,500		)
Debt issuance costs	—			(15,613		)	—			—			—			(15,613		)
Payment of redemption and call premiums on senior notes	—			(17,913		)	—			—			—			(17,913		)
Proceeds from ATM Program issuances, net of costs	17,259			—			—			—			—			17,259
Contribution from General Partner	465			—			—			—			—			465
Issuance of senior notes	—			500,000			—			—			—			500,000
Tender and redemption of senior notes	—			(300,000		)	—			—			—			(300,000		)
Other, net	(2,632		)	—			336			28			—			(2,268		)
Advances from affiliates	74,440			—			—			(5,536		)	(68,904		)	—
Net cash provided by (used in) financing activities	503			9,474			336			(5,508		)	(68,904		)	(64,099		)
Net change in cash and cash equivalents	(470		)	28			(3,726		)	(672		)	—			(4,840		)
Cash and cash equivalents, beginning of period	698			51			5,647			1,032			—			7,428
Cash and cash equivalents, end of period	$	228		$	79		$	1,921		$	360		$	—		$	2,588

33

	Six months ended June 30, 2016
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	750		$	(28,517	)	$	119,435		$	39,832		$	—		$	131,500
Cash flows from investing activities:
Capital expenditures	(512		)	—			(30,745		)	(60,115		)	—			(91,372		)
Contributions to equity method investees	—			—			—			(15,645		)	—			(15,645		)
Acquisitions of gathering systems from affiliate	(359,431		)	—			—			—			—			(359,431		)
Other, net	(435		)	—			—			—			—			(435		)
Advances to affiliates	(8,978		)	(357,486		)	(93,269		)	—			459,733			—
Net cash used in investing activities	(369,356		)	(357,486		)	(124,014		)	(75,760		)	459,733			(466,883		)
Cash flows from financing activities:
Distributions to unitholders	(82,020		)	—			—			—			—			(82,020		)
Borrowings under Revolving Credit Facility	12,000			427,300			—			—			—			439,300
Repayments under Revolving Credit Facility	—			(50,300		)	—			—			—			(50,300		)
Debt issuance costs	—			(2,766		)	—			—			—			(2,766		)
Cash advance from Summit Investments to contributed subsidiaries, net	(12,000		)	—			—			24,214			—			12,214
Expenses paid by Summit Investments on behalf of contributed subsidiaries	3,030			—			—			1,791			—			4,821
Other, net	(912		)	—			—			(4		)	—			(916		)
Advances from affiliates	450,755			—			—			8,978			(459,733		)	—
Net cash provided by financing activities	370,853			374,234			—			34,979			(459,733		)	320,333
Net change in cash and cash equivalents	2,247			(11,769		)	(4,579		)	(949		)	—			(15,050		)
Cash and cash equivalents, beginning of period	73			12,407			6,930			2,383			—			21,793
Cash and cash equivalents, end of period	$	2,320		$	638		$	2,351		$	1,434		$	—		$	6,743

34

18. SUBSEQUENT EVENTS

We have evaluated subsequent events for recognition or disclosure in the unaudited condensed consolidated financial statements filed on Form 10-Q with the SEC and no events have occurred that require disclosure, except for the following:

In July 2017, our newly formed subsidiary, Summit Midstream Permian, LLC, executed an agreement with XTO Energy Inc. (“XTO”) to develop, own and operate a new associated natural gas gathering and processing system servicing XTO’s crude oil production from certain acreage located in the northern Delaware Basin in Eddy and Lea counties in New Mexico. We will initially construct a gathering and processing system with high and low pressure gathering and discharge pipelines, two compressor stations and a cryogenic processing plant with 60 million cubic feet per day (“MMcf/d”) of processing capacity. Our processing complex will have the ability to be expanded to over 600 MMcf/d of processing capacity, as warranted, to meet customer needs. We expect to process production from XTO and other nearby producers. The initial phase of the project is expected to be operational on or before June 1, 2018 at a total investment cost of approximately $110.0 million.

Item 2. 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, 2016. 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 2016 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 Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.

This MD&A comprises the following sections:

• Overview

• Trends and Outlook

• How We Evaluate Our Operations

• Results of Operations

• Liquidity and Capital Resources

• Critical Accounting Estimates

• Forward-Looking Statements

Overview

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

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

• 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;

35

• 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;

• Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; and

• Summit Permian, an associated natural gas gathering and processing system under development in the northern Delaware Basin in southeastern New Mexico.

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

Our financial results are driven primarily by volume throughput and expense management. We generate the majority of our revenues from the gathering, treating and processing services that we provide to our customers. A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from (i) the sale of physical natural gas and NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. These additional activities, which expose us to direct commodity price risk, accounted for less than 10% of total revenues during the six months ended June 30, 2017.

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.

36

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

	Three months ended June 30,					Six months ended June 30,
	2017		2016			2017			2016
	(In thousands)
Net income (loss)	$	11,246	$	(50,555	)	$	10,663		$	(54,220	)
Reportable segment adjusted EBITDA:
Utica Shale	9,533		4,727			17,445			7,916
Ohio Gathering	9,606		12,725			18,679			25,113
Williston Basin	17,155		19,209			34,964			38,929
Piceance/DJ Basins	27,274		26,231			56,248			51,046
Barnett Shale	12,998		13,913			25,086			27,990
Marcellus Shale	5,446		4,807			11,093			9,408
Net cash provided by operating activities	$	58,892	$	64,651		$	121,341		$	131,500
Acquisitions of gathering systems (1)	—		(569		)	—			866,858
Capital expenditures (2)	31,484		30,046			45,912			91,372
Contributions to equity method investees	10,713		—			15,649			15,645
Distributions to unitholders	$	44,577	$	41,045		$	89,029		$	82,020
Issuance of senior notes	—		—			500,000			—
Tender and redemption of senior notes	—		—			(300,000		)	—
Net borrowings (repayments) under Revolving Credit Facility	16,000		—			(157,000		)	389,000
Proceeds from ATM Program issuances, net of costs	16,892		—			17,259			—

_________

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

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

Three and six months ended June 30, 2017. The following items are reflected in our financial results:

• In March 2017, we recognized $37.7 million of gathering services and related fees revenue that had been previously deferred in connection with an MVC arrangement with a certain Williston Basin customer, for which we determined we had no further performance obligations. We include the effect of adjustments related to MVC shortfall payments in our definition of segment adjusted EBITDA. As such, the Williston Basin 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 unaudited condensed consolidated financial statements).

• In February 2017, we completed a public offering of $500.0 million principal 5.75% Senior Notes. Concurrent with and following the offering, we tendered and redeemed all of the outstanding 7.5% Senior Notes. The remaining 7.5% Senior Notes were redeemed on March 18, 2017, with payment made on March 20, 2017. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

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

• In June 2016, an impairment loss was recognized by OCC. We recorded our 40% share of the impairment loss, or $37.8 million, in loss from equity method investees in the unaudited condensed consolidated statements of operations (see Note 7 to the unaudited condensed consolidated financial statements).

• 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

37

Purchase Price Obligation with Summit Investments (see Note 16 to the unaudited condensed consolidated financial statements).

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; 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 2016 Annual Report.

How We Evaluate Our Operations

We conduct and report our operations in the midstream energy industry through six reportable segments. We evaluate our business operations each reporting period to determine whether any of our gathering system operating segments in which we internally report financial information are considered significant and would require us to separately disclose certain segment financial information in our external reporting. As a result of our evaluation for the three-months ended June 30, 2017, we determined that both the Summit Utica natural gas gathering system and the Ohio Gathering natural gas gathering system, each previously reported within the Utica Shale reportable segment, were and are expected to continue to be significant operating segments. As such, we are modifying our current segments such that the Utica Shale reportable segment includes the Summit Utica gathering system and the Ohio Gathering reportable segment includes our ownership interest in OGC and OCC. For the three- and six-months ended June 30, 2017, we have disclosed the required segment information for Summit Utica and Ohio Gathering and the periods prior to January 1, 2017 have been recast to reflect this change. Our reportable segments are as follows:

• the Utica Shale, which is served by Summit Utica;

• Ohio Gathering, which includes our ownership interest in OGC and OCC;

• 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 (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 during the three and six months ended June 30, 2017.

Additional Information. For additional information, see the "Results of Operations" section herein and the notes to the unaudited condensed consolidated financial statements. 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 2016 Annual

38

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.

Results of Operations

Consolidated Overview of the Three and Six Months Ended June 30, 2017 and 2016

The following table presents certain consolidated and operating data.

	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	84,801		$	76,187		$	202,814		$	154,287
Natural gas, NGLs and condensate sales	10,595			8,581			21,715			16,169
Other revenues	6,396			4,867			13,068			9,750
Total revenues	101,792			89,635			237,597			180,206
Costs and expenses:
Cost of natural gas and NGLs	9,099			6,864			18,151			13,154
Operation and maintenance	24,016			23,410			47,708			49,252
General and administrative	12,949			12,876			27,081			25,755
Depreciation and amortization	28,688			27,963			57,257			55,691
Transaction costs	119			122			119			1,296
Loss on asset sales, net	67			74			70			11
Long-lived asset impairment	3			569			287			569
Total costs and expenses	74,941			71,878			150,673			145,728
Other income	64			19			135			41
Interest expense	(17,553		)	(16,035		)	(34,269		)	(31,917		)
Early extinguishment of debt	—			—			(22,020		)	—
Deferred Purchase Price Obligation	5,058			(17,465		)	(15,825		)	(24,928		)
Income (loss) before income taxes and loss from equity method investees	14,420			(15,724		)	14,945			(22,326		)
Income tax benefit (expense)	211			(360		)	(241		)	(283		)
Loss from equity method investees	(3,385		)	(34,471		)	(4,041		)	(31,611		)
Net income (loss)	$	11,246		$	(50,555	)	$	10,663		$	(54,220	)
Volume throughput (1):
Aggregate average daily throughput – natural gas (MMcf/d)	1,780			1,512			1,704			1,518
Aggregate average daily throughput – liquids (Mbbl/d)	68.9			86.0			72.6			90.5

__________

(1) Exclusive of volume throughput for Ohio Gathering. For additional information, see the "Ohio Gathering" section herein.

Volumes – Gas. Natural gas throughput volumes increased268 MMcf/d compared to the three months ended June 30, 2016, primarily reflecting:

• a volume throughput increase of 246 MMcf/d for the Utica Shale segment.

• a volume throughput increase of 64 MMcf/d for the Marcellus Shale segment.

• a volume throughput increase of 32 MMcf/d for the Piceance/DJ Basins segment.

• a volume throughput decrease of 70 MMcf/d for the Barnett Shale segment.

39

Natural gas throughput volumes increased186 MMcf/d compared to the six months ended June 30, 2016, primarily reflecting:

• a volume throughput increase of 194 MMcf/d for the Utica Shale segment.

• a volume throughput increase of 37 MMcf/d for the Piceance/DJ Basins segment.

• a volume throughput increase of 22 MMcf/d for the Marcellus Shale segment.

• a volume throughput decrease of 62 MMcf/d for the Barnett Shale segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased compared to the three and six months ended June 30, 2016, primarily reflecting decreased drilling activity and natural production declines.

Revenues. Total revenues increased $12.2 million, or 14%, compared to the three months ended June 30, 2016 primarily reflecting:

• a $5.1 millionincrease for the Utica Shale segment due to the ongoing development of the Summit Utica system.

• a $2.0 million increase in natural gas, NGLs and condensate sales primarily due to increases for the Williston Basin segment of $1.7 million and the Piceance/DJ Basins segment of approximately $0.4 million primarily as a result of higher commodity prices and the addition of natural gas and crude oil marketing services.

• a $4.0 million increase in gathering services and related fees for the Piceance/DJ Basins segment primarily as a result of ongoing drilling and completion activity.

Total revenues increased $57.4 million, or 32%, compared to the six months ended June 30, 2016 primarily reflecting:

• the recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

• the recognition of $2.6 million of business interruption recoveries for the Williston Basin segment.

• a $9.6 millionincrease for the Utica Shale segment due to the ongoing development of the Summit Utica system.

• a $7.8 million increase in gathering services and related fees for the Piceance/DJ Basins segment primarily as a result of ongoing drilling and completion activity and the addition of natural gas and crude oil marketing services.

• a $2.6 million decrease for the Barnett Shale segment primarily due to lower volume throughput on the DFW Midstream system.

Gathering Services and Related Fees. The increase in gathering services and related fees compared to the three months ended June 30, 2016 primarily reflected:

• a $5.1 millionincrease for the Utica Shale segment due to the ongoing development of the Summit Utica system.

• a $4.0 million increase for the Piceance/DJ Basins segment primarily as a result of ongoing drilling and completion activity.

• a $0.9 million increase for the Marcellus Shale segment primarily due to increased drilling and completion activity.

• a $1.4 milliondecrease for the Barnett Shale segment primarily due to lower volume throughput on the DFW Midstream system.

The increase in gathering services and related fees compared to the six months ended June 30, 2016 primarily reflected:

• the recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

• the recognition of $2.6 million of business interruption recoveries for the Williston Basin segment.

• a $9.6 millionincrease for the Utica Shale segment due to the ongoing development of the Summit Utica system.

40

• a $7.8 million increase for the Piceance/DJ Basins segment primarily as a result of ongoing drilling and completion activity.

• a $5.4 milliondecrease for the Barnett Shale segment primarily due to lower volume throughput on the DFW Midstream system.

• a $4.5 million decrease, after taking into account the recognition of $37.7 million of previously deferred revenue and $2.6 million of business interruption recoveries, for the Williston Basin segment, primarily as a result of natural production declines and decreased drilling activity.

Natural Gas, NGLs and Condensate Sales. The increase in natural gas, NGLs and condensate sales for the three and six months ended June 30, 2017 primarily reflected the impact on pricing and throughput of higher commodity prices on our Williston Basin and Piceance/DJ Basins segments and the addition of natural gas and crude oil marketing services provided for the Piceance/DJ Basins segment.

Costs and Expenses. Total costs and expenses increased $3.1 million, or 4%, compared to the three months ended June 30, 2016 primarily reflecting:

• a $2.2 million increase in cost of natural gas and NGLs primarily for the Williston Basin segment due to the impact of increasing commodity prices on their percent-of-proceeds and condensate sales activity.

• a $0.6 million increase in operation and maintenance expenses primarily due to costs associated with repairs in the Marcellus Shale and Piceance/DJ Basins segments, partially offset by certain environmental remediation expenses in the Williston Basin segment recognized in 2016.

Total costs and expenses increased $4.9 million, or 3%, compared to the six months ended June 30, 2016 primarily reflecting:

• a $5.0 million increase in cost of natural gas and NGLs primarily for the Williston Basin segment of $3.6 million and Piceance/DJ Basins segment of $0.6 million due to the impact of increasing commodity prices on their percent-of-proceeds and condensate sales activity and the addition of natural gas and crude oil marketing services provided for the Piceance/DJ Basins segment.

Cost of Natural Gas and NGLs.The increase in cost of natural gas and NGLs compared to the three and six months ended June 30, 2016 largely reflected the impact on pricing and throughput of higher comparative commodity prices on our Williston Basin and Piceance/DJ Basins segments and the associated impact on (i) our percent-of-proceeds arrangements for the Bison Midstream system and (ii) our percent-of-proceeds arrangements and condensate sales for the Grand River system.

Operation and Maintenance. Operation and maintenance expense increased compared to the three months ended June 30, 2016 primarily due to costs associated with repairs in the Marcellus Shale and Piceance/DJ Basins segments, partially offset by certain environmental remediation expenses in the Williston Basin recognized in 2016.

Operation and maintenance expense decreased compared to the six months ended June 30, 2016 primarily reflecting a decrease in expenses associated with repairs to rights-of-ways in the Marcellus Shale segment and certain environmental remediation expenses in the Williston Basin segment recognized in 2016. The decrease was partially offset by costs associated with repairs in the Marcellus Shale and Piceance/DJ Basins segments during the six months ended June 30, 2017.

General and Administrative. General and administrative expense increased compared to the six months ended June 30, 2016 primarily reflecting an increase in salaries and benefits.

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

Transaction Costs. Transaction costs recognized during the six months ended June 30, 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.

Interest Expense. The increase in interest expense compared to the three and six months ended June 30, 2016 was primarily driven by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes partially offset by a decrease resulting from the tender and redemption of the $300.0 million principal 7.5% Senior Notes and a decrease in the outstanding portion on the Revolving Credit Facility.

Early Extinguishment of Debt. The early extinguishment of debt recognized during the six months ended June 30, 2017 was driven by the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

41

Deferred Purchase Price Obligation. The change in the Deferred Purchase Price Obligation recognized during the three and six months ended June 30, 2017 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 16 to the unaudited condensed consolidated financial statements).

For additional information, see the "Segment Overview of the Three Months Ended June 30, 2017 and 2016" and "Corporate and Other Overview of the Three Months Ended June 30, 2017 and 2016" sections herein.

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

Volume throughput for our Summit Utica system follows.

	Utica Shale
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2017	2016		2017	2016
Average daily throughput (MMcf/d)	413	167	147%	344	150	129%

Volume throughput increased compared to the three and six months ended June 30, 2016 due to the ongoing development of the Summit Utica system and completion of new wells during the second half of 2016 and the first half of 2017.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended June 30,				Percentage Change	Six months ended June 30,				Percentage Change
	2017		2016			2017		2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	10,456	$	5,403	94%	$	19,252	$	9,686	99%
Total revenues	10,456		5,403		94%	19,252		9,686		99%
Costs and expenses:
Operation and maintenance	842		495		70%	1,605		1,020		57%
General and administrative	81		181		(55)%	202		750		(73)%
Depreciation and amortization	1,748		952		84%	3,395		1,796		89%
Long-lived asset impairment	—		—		*	284		—		*
Total costs and expenses	2,671		1,628		64%	5,486		3,566		54%
Add:
Depreciation and amortization	1,748		952			3,395		1,796
Long-lived asset impairment	—		—			284		—
Segment adjusted EBITDA	$	9,533	$	4,727	102%	$	17,445	$	7,916	120%

__________

* Not considered meaningful

Three months ended June 30, 2017. Segment adjusted EBITDA increased$4.8 million compared to the three months ended June 30, 2016 primarily reflecting:

• a $5.1 millionincrease in gathering services and related fees primarily due to the increase in volume throughput and ongoing development of the Summit Utica system.

Other items to note:

• Depreciation and amortization increased compared to the three months ended June 30, 2016 as a result of placing assets into service in the Summit Utica system.

42

Six months ended June 30, 2017. Segment adjusted EBITDA increased$9.5 million compared to the six months ended June 30, 2016 primarily reflecting:

• a $9.6 millionincrease in gathering services and related fees primarily due to the increase in volume throughput and ongoing development of the Summit Utica system.

Other items to note:

• Depreciation and amortization increased compared to the six months ending June 30, 2016 as a result of placing assets into service in the Summit Utica system.

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

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

	Ohio Gathering
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2017	2016		2017	2016
Average daily throughput (MMcf/d)	706	937	(25)%	737	903	(18)%

Volume throughput for the Ohio Gathering system, which is based on a one-month lag, decreased compared to the three and six months ended June 30, 2016 primarily as a result of decreased drilling activity and natural production declines. The decrease for the three months ended June 30, 2017 was partially offset by increased volumes associated with the installation of additional compression in the dry gas window beginning in March 2017.

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

	Ohio Gathering
	Three months ended June 30,				Percentage Change	Six months ended June 30,				Percentage Change
	2017		2016			2017		2016
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	9,606	$	12,725	(25)%	$	18,679	$	25,113	(26)%
Segment adjusted EBITDA	$	9,606	$	12,725	(25)%	$	18,679	$	25,113	(26)%

Segment adjusted EBITDA for equity method investees decreased compared to the three months and six months ended June 30, 2016 primarily due to decreased drilling activity and natural production declines. The decrease for the three months ended June 30, 2017 was partially offset by increased volumes associated with the installation of additional compression in the dry gas window beginning in March 2017.

Williston Basin. The Bison Midstream, Polar and Divide and Tioga Midstream systems provide our midstream services for the Williston Basin reportable segment. Polar and Divide was acquired from subsidiaries of Summit Investments in May 2015, with additional assets that currently comprise a portion of the Polar and Divide system, subsequently acquired from Summit Investments in March 2016. Tioga Midstream was acquired from a subsidiary of Summit Investments in March 2016.

43

Volume throughput for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2017	2016		2017	2016
Aggregate average daily throughput – natural gas (MMcf/d)	20	24	(17)%	19	24	(21)%
Aggregate average daily throughput – liquids (Mbbl/d)	68.9	86.0	(20)%	72.6	90.5	(20)%

Natural gas. Natural gas volume throughput decreased compared to the three and six months ended June 30, 2016 largely reflecting natural production declines and decreased drilling activity.

Liquids. The decrease in liquids volume throughput compared to the three and six months ended June 30, 2016 largely reflected natural production declines and decreased drilling activity.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended June 30,				Percentage Change	Six months ended June 30,					Percentage Change
	2017		2016			2017			2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	19,721	$	19,536	1%	$	77,706		$	41,951	85%
Natural gas, NGLs and condensate sales	6,648		4,918		35%	12,806			9,196		39%
Other revenues	2,745		3,053		(10)%	5,487			6,370		(14)%
Total revenues	29,114		27,507		6%	95,999			57,517		67%
Costs and expenses:
Cost of natural gas and NGLs	6,850		4,980		38%	13,212			9,606		38%
Operation and maintenance	6,339		6,991		(9)%	12,802			15,202		(16)%
General and administrative	752		588		28%	1,292			1,577		(18)%
Depreciation and amortization	8,385		8,410		—%	16,766			16,767		—%
Loss on asset sales, net	56		3		*	59			2		*
Long-lived asset impairment	3		569		*	3			569		*
Total costs and expenses	22,385		21,541		4%	44,134			43,723		1%
Add:
Depreciation and amortization	8,385		8,410			16,766			16,767
Adjustments related to MVC shortfall payments	1,982		4,261			(33,729		)	7,797
Loss on asset sales, net	56		3			59			2
Long-lived asset impairment	3		569			3			569
Segment adjusted EBITDA	$	17,155	$	19,209	(11)%	$	34,964		$	38,929	(10)%

__________

* Not considered meaningful

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Three months ended June 30, 2017. Segment adjusted EBITDA decreased$2.1 million compared to the three months ended June 30, 2016 primarily reflecting:

• a decrease in liquids volumes partially offset by the recognition of $2.3 million in gathering services fees relating to previously billed but unearned revenue.

Six months ended June 30, 2017. Segment adjusted EBITDA decreased$4.0 million compared to the six months ended June 30, 2016 primarily reflecting:

• a decrease in liquids volumes partially offset by $2.6 million of business interruption recoveries and the recognition of $2.3 million in gathering services fees relating to previously billed but unearned revenue.

• a $2.4 milliondecrease in operation and maintenance expenses primarily due to costs associated with certain environmental remediation expenses recognized in 2016.

Other items to note:

• The adjustments for MVC shortfall payments is primarily driven by the recognition of $37.7 million of gathering services and related fees revenue that had been previously deferred in connection with an MVC arrangement with a certain Williston Basin customer, for which we determined we had no further performance obligations. As a result, the increase in gathering services and related fees compared with the first half of 2016 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).

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

Volume throughput for our Piceance/DJ Basins reportable segment follows.

	Piceance/DJ Basins
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2017	2016		2017	2016
Aggregate average daily throughput (MMcf/d)	596	564	6%	605	568	7%

Volume throughput increased compared to the three and six months ended June 30, 2016 primarily as a result of ongoing drilling and completion activity across our gathering footprint.

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

	Piceance/DJ Basins
	Three months ended June 30,				Percentage Change	Six months ended June 30,				Percentage Change
	2017		2016			2017		2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	29,367	$	25,401	16%	$	58,641	$	50,792	15%
Natural gas, NGLs and condensate sales	2,814		2,425		16%	6,571		4,627		42%
Other revenues	1,582		1,585		—%	3,359		2,983		13%
Total revenues	33,763		29,411		15%	68,571		58,402		17%
Costs and expenses:
Cost of natural gas and NGLs	1,927		1,884		2%	4,110		3,548		16%
Operation and maintenance	9,299		8,186		14%	18,078		16,782		8%
General and administrative	599		566		6%	1,224		1,999		(39)%
Depreciation and amortization	12,225		12,297		(1)%	24,436		24,570		(1)%
Loss on asset sales, net	3		71		*	3		9		*
Total costs and expenses	24,053		23,004		5%	47,851		46,908		2%
Add:
Depreciation and amortization	12,225		12,297			24,436		24,570
Adjustments related to MVC shortfall payments	5,336		7,456			11,089		14,973
Loss on asset sales, net	3		71			3		9
Segment adjusted EBITDA	$	27,274	$	26,231	4%	$	56,248	$	51,046	10%

__________

* Not considered meaningful

Three months ended June 30, 2017. Segment adjusted EBITDA increased$1.0 million compared to the three months ended June 30, 2016 primarily reflecting:

• a $1.8 million increase, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.

• a $0.4 millionincrease in natural gas, NGLs and condensate sales due to higher commodity prices.

• a $1.1 million increase in operation and maintenance expense primarily related to repairs to compressors.

Six months ended June 30, 2017. Segment adjusted EBITDA increased$5.2 million compared to the six months ended June 30, 2016 primarily reflecting:

• a $4.0 million increase, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.

• a $1.9 millionincrease in natural gas, NGLs and condensate sales due to higher commodity prices offset by a $0.6 millionincrease in cost of natural gas and NGLs.

• a $1.3 million increase in operation and maintenance expense primarily related to repairs to compressors.

Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment.

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Volume throughput for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2017	2016		2017	2016
Average daily throughput (MMcf/d)	271	341	(21)%	279	341	(18)%

Volume throughput declined compared to the three and six months ended June 30, 2016 reflecting reduced drilling and completion activity, in addition to natural production declines.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended June 30,						Percentage Change	Six months ended June 30,						Percentage Change
	2017			2016				2017			2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	17,957		$	19,389		(7)%	$	33,081		$	38,514		(14)%
Natural gas, NGLs and condensate sales	872			1,238			(30)%	1,331			2,346			(43)%
Other revenues (1)	2,075			229			*	4,234			397			*
Total revenues	20,904			20,856			—%	38,646			41,257			(6)%
Costs and expenses:
Operation and maintenance	5,719			6,178			(7)%	12,251			12,492			(2)%
General and administrative	296			312			(5)%	585			548			7%
Depreciation and amortization	3,913			3,928			—%	7,826			7,847			—%
Loss on asset sales, net	8			—			*	8			—			*
Total costs and expenses	9,936			10,418			(5)%	20,670			20,887			(1)%
Add:
Depreciation and amortization (1)	3,762			4,057				7,524			8,113
Adjustments related to MVC shortfall payments	(1,740		)	(582		)		(422		)	(493		)
Loss on asset sales, net	8			—				8			—
Segment adjusted EBITDA	$	12,998		$	13,913		(7)%	$	25,086		$	27,990		(10)%

__________

*Not considered meaningful

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

Three months ended June 30, 2017. Segment adjusted EBITDA decreased$0.9 million compared to the three months ended June 30, 2016 primarily reflecting:

• a $1.4 million decrease in gathering services and related fees largely as a result of reduced drilling activity and natural production declines.

• a $1.8 million increase in other revenues primarily due to electricity expense reimbursements that we began passing through to certain customers beginning in the fourth quarter of 2016.

Six months ended June 30, 2017. Segment adjusted EBITDA decreased$2.9 million compared to the six months ended June 30, 2016 primarily reflecting:

• a $5.4 milliondecrease in gathering services and related fees largely as a result of reduced drilling activity and natural production declines.

• a $3.8 millionincrease in other revenues primarily due to electricity expense reimbursements that we began passing through to certain customers beginning in the fourth quarter of 2016.

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

Volume throughput for the Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended June 30,		Percentage Change	Six months ended June 30,		Percentage Change
	2017	2016		2017	2016
Average daily throughput (MMcf/d)	480	416	15%	457	435	5%

Volume throughput increased compared to the three and six months ended June 30, 2016 primarily due to increased drilling and completion activity.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended June 30,				Percentage Change	Six months ended June 30,				Percentage Change
	2017		2016			2017		2016
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,365	$	6,458	14%	$	14,269	$	13,344	7%
Total revenues	7,365		6,458		14%	14,269		13,344		7%
Costs and expenses:
Operation and maintenance	1,818		1,560		17%	2,976		3,756		(21)%
General and administrative	101		91		11%	200		180		11%
Depreciation and amortization	2,263		2,222		2%	4,526		4,441		2%
Total costs and expenses	4,182		3,873		8%	7,702		8,377		(8)%
Add:
Depreciation and amortization	2,263		2,222			4,526		4,441
Segment adjusted EBITDA	$	5,446	$	4,807	13%	$	11,093	$	9,408	18%

Three months ended June 30, 2017. Segment adjusted EBITDA increased$0.6 million compared to the three months ended June 30, 2016 primarily reflecting:

• a $0.9 million increase in gathering services and related fees primarily as a result of increased drilling and completion activity.

• a $0.3 million increase in operation and maintenance primarily as a result of costs associated with repairs to rights-of-way.

Six months ended June 30, 2017. Segment adjusted EBITDA increased$1.7 million compared to the six months ended June 30, 2016 primarily reflecting:

• a $0.9 millionincrease in gathering services and related fees primarily as a result of increased drilling and completion activity.

• a $0.8 milliondecrease in operation and maintenance primarily as a result of a decrease in expenses associated with repairs to rights-of-way during the six months ended June 30, 2016.

Corporate and Other Overview for the Three and Six Months ended June 30, 2017 and 2016

Corporate and other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, transaction costs, interest expense, early extinguishment of debt and a change in the Deferred Purchase Price Obligation fair value. Total revenue attributable to Corporate and other is

48

$1.4 million for the three months ended June 30, 2017 and $3.1 million for the six months ended June 30, 2017 (see Note 3 to the unaudited condensed consolidated financial statements). Other items to note follow.

	Corporate and Other
	Three months ended June 30,					Percentage Change	Six months ended June 30,				Percentage Change
	2017			2016			2017		2016
	(Dollars in thousands)
Costs and expenses:
General and administrative	$	11,117		$	11,138	—%	$	23,571	$	20,701	14%
Transaction costs	119			122		*	119		1,296		*
Interest expense (1)	17,553			16,035		9%	34,269		31,917		7%
Early extinguishment of debt (2)	—			—		*	22,020		—		*
Deferred Purchase Price Obligation	(5,058		)	17,465		*	15,825		24,928		*

__________

* Not considered meaningful

(1) Includes interest expense on debt allocated to the 2016 Drop Down Assets during the common control period.

(2) Early extinguishment of debt includes $17.9 million paid for redemption and call premiums, as well as $4.1 million of unamortized debt issuance costs which were written off in connection with the repurchase of the outstanding $300.0 million 7.5% Senior Notes in the first quarter of 2017.

General and Administrative. General and administrative expense increased compared to the six months ended June 30, 2016 primarily reflecting an increase in salaries and benefits.

Transaction Costs. Transaction costs recognized during the six months ended June 30, 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down.

Interest Expense. The increase in interest expense compared to the three and six months ended June 30, 2016 was primarily driven by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes partially offset by a decrease resulting from the tender and redemption of the $300.0 million principal 7.5% Senior Notes and a decrease in the outstanding portion on the Revolving Credit Facility.

Early Extinguishment of Debt. The early extinguishment of debt recognized during the six months ended June 30, 2017 was driven by the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

Deferred Purchase Price Obligation. The change in the Deferred Purchase Price Obligation recognized during the three and six months ended June 30, 2017 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 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 flows generated from our operations, borrowings under our Revolving Credit Facility and future issuances of equity and debt instruments.

Capital Markets Activity

Capital markets activity during the six months ended June 30, 2017 follows.

July 2017 Shelf Registration Statement. In July 2017, we filed the 2017 SRS with the SEC to issue an indeterminate amount of debt, equity securities and guarantees. The 2017 SRS replaced the 2014 SRS which expired on July 10, 2017. No transactions have been executed pursuant to the 2017 SRS. The 2017 SRS expires in July 2020.

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

• In February 2017, we completed a secondary public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments in accordance with our obligations under our partnership agreement. We did not receive any proceeds from this secondary offering.

49

• In February 2017, we executed a new equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million. These sales are made (i) pursuant to the terms of the equity distribution agreement between us and the sales agents named therein and (ii) by means of ordinary brokers' transactions at market prices, in block transactions or as otherwise agreed between us and the sales agents. Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rules. During the three months ended June 30, 2017, we sold 745,848 units under the ATM Program for aggregate gross proceeds of $17.3 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. During the six months ended June 30, 2017, we issued 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. Our General Partner made capital contributions to maintain its 2% general partner interest in SMLP.

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

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

On February 8, 2017, we amended the 2014 SRS to include additional guarantor subsidiaries and completed a public offering of $500.0 million principal 5.75% senior unsecured notes due 2025. Concurrent therewith, we made a tender offer to purchase all the outstanding 7.5% Senior Notes. The tender offer expired on February 14, 2017 with $276.9 million validly tendered. On February 16, 2017, we issued a notice of redemption for the 7.5% Senior Notes that remained outstanding subsequent to the tender offer. The remaining 7.5% Senior Notes were redeemed on March 18, 2017, with payment made on March 20, 2017. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

For additional information, see Notes 9 and 11 to the unaudited condensed consolidated financial statements.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured revolving credit facility. On May 26, 2017, Summit Holdings closed on the Third Amended and Restated Credit Agreement which extended the maturity from November 2018 to May 2022 (see Note 9 to the unaudited condensed consolidated financial statements). As of June 30, 2017, the outstanding balance of the Revolving Credit Facility was $491.0 million and the unused portion totaled $759.0 million. There were no defaults or events of default during the first half of 2017 and, as of June 30, 2017, we were in compliance with the covenants in the Revolving Credit Facility.

Senior Notes. In February 2017, the Co-Issuers co-issued the 5.75% Senior Notes. There were no defaults or events of default during the first half of 2017 on any series of senior notes.

For additional information on our long-term debt, 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

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

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

	Six months ended June 30,
	2017			2016
	(In thousands)
Net cash provided by operating activities	$	121,341		$	131,500
Net cash used in investing activities	(62,082		)	(466,883		)
Net cash (used in) provided by financing activities	(64,099		)	320,333
Net change in cash and cash equivalents	$	(4,840	)	$	(15,050	)

Operating activities. Cash flows from operating activities for the six months ended June 30, 2017 primarily reflected:

• a $6.2 million decrease in distributions from Ohio Gathering; and

• a $1.9 million increase in cash interest payments.

Investing activities. Cash flows used in investing activities during the six months ended June 30, 2017 primarily reflected:

• $45.9 million of capital expenditures primarily attributable to the ongoing development of the Summit Utica system as well as the continued development in the Williston Basin and Piceance/DJ Basins segments; and

• $15.6 million of capital contributions to Ohio Gathering.

Cash flows used in investing activities during the six months ended June 30, 2016 primarily reflected:

• $360.0 million consideration paid and recognized in connection with the 2016 Drop Down;

• $91.4 million of capital expenditures primarily attributable to the ongoing development of the Summit Utica system and Williston Basin segment; and

• $15.6 million of capital contributions to Ohio Gathering.

Financing activities. Cash flows used in financing activities during the six months ended June 30, 2017 primarily reflected:

• $300.0 million paid for the repurchase of the outstanding 7.5% Senior Notes;

• $17.9 million paid for the redemption and call premiums on the 7.5% Senior Notes;

• $157.0 million of net repayments under our Revolving Credit Facility;

• $89.0 million of distributions; and

• $500.0 million of borrowings from the issuance of 5.75% Senior Notes.

Cash flows provided by financing activities during the six months ended June 30, 2016 primarily reflected:

• $389.0 million of net borrowings under our Revolving Credit Facility primarily to fund the 2016 Drop Down; and

• $82.0 million of distributions.

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. The Deferred Purchase Price Obligation is due no later than December 31, 2020 and is currently expected to be $793.3 million based on information available as of June 30, 2017. There are no cash interest payments associated with the Deferred Purchase Price Obligation.

In February 2017, we issued $500.0 million principal of 5.75% senior, unsecured notes due 2025. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

51

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 six months ended June 30, 2017, cash paid for capital expenditures totaled $45.9 million (see Note 3 to the unaudited condensed consolidated financial statements) which included $8.1 million of maintenance capital expenditures. For the six months ended June 30, 2017, contributions to equity method investees totaled $15.6 million (see Note 7 to the unaudited condensed consolidated financial statements).

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 objectives for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

Distributions, Including IDRs

Based on the terms of our Partnership Agreement, we expect to distribute most of the cash generated by our operations to our unitholders. With respect to our payment of IDRs to the General Partner, we reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013. We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014. For additional information, see 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 customer’s wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customer’s commodities flow and, in many cases, the only way for our customers to get their production to market.

We estimate the quarterly impact of expected MVC shortfall payments for inclusion in our calculation of 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

For additional information, 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 six months ended June 30, 2017.

52

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. There have been no changes to our significant accounting policies since December 31, 2016.

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 six months ended June 30, 2017.

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 our customers' drilling efforts, as well as the quantity of natural gas and crude oil volumes produced within proximity of our assets;

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

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

• actions or inactions taken or nonperformance 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 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;

• 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;

53

• 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 terrain in certain areas in which we operate;

• any other issues that can result in deficiencies in the design, installation or operation of our gathering, treating and processing facilities;

• 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;

• changes in tax status;

• the effects of litigation;

• changes in general economic conditions; and

• certain factors discussed elsewhere in this report.

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our debt portfolio. As of June 30, 2017, we had $800.0 million principal of fixed-rate Senior Notes and $491.0 million outstanding under our variable rate Revolving Credit Facility (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, 2016. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2016 Annual Report.

Commodity Price Risk

We currently generate a substantial majority of our revenues pursuant to primarily long-term and fee-based 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 certain DFW Midstream system 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, (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 and (v) our purchase and sale of natural gas relating to certain marketing services. Our current commodity price risk exposure has not changed materially since December 31, 2016. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2016 Annual Report.

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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 June 30, 2017 and (ii) no change in internal control over financial reporting occurred during the quarter ended June 30, 2017, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 Note 15 to our unaudited condensed consolidated financial statements “Commitments and Contingencies-Legal Proceedings” and in the 2016 Annual Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of the 2016 Annual Report are incorporated herein by reference except to the extent they address risks arising from or relating to the failure of events described therein to occur, which events have since occurred.

Item 6. Exhibits.

Exhibit number		Description
3.1		First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.2		Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1		Third Amended and Restated Credit Agreement dated as of May 26, 2017 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated May 30, 2017 (Commission File No. 001-35666))
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Executive Vice President and Chief Financial Officer
32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, and Matthew S. Harrison, Executive Vice President and Chief Financial Officer
101.INS	**	XBRL Instance Document (1)
101.SCH	**	XBRL Taxonomy Extension Schema
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	XBRL Taxonomy Extension Label Linkbase
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase

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

(1) Includes the following materials contained in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, 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)
August 4, 2017	/s/ Matthew S. Harrison
	Matthew S. Harrison, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

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