Summit Midstream Partners 10Q 2018 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2018

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

For the transition period from to

Commission file number: 001-35666

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

45-5200503

(I.R.S. Employer

Identification No.)

1790 Hughes Landing Blvd, Suite 500

The Woodlands, TX

(Address of principal executive offices)

77380

(Zip Code)

(832) 413-4770

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and formal fiscal year, 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. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

☒ Yes ☐ 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 ☒		Accelerated filer ☐

Non-accelerated filer ☐		Smaller reporting company ☐

Emerging growth company ☐

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. ☐

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

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

Class		As of October 31, 2018

Common Units		73,356,950 units

General Partner Units		1,490,999 units

TABLE OF CONTENTS

COMMONLY USED OR DEFINED TERMS		2

PART I	FINANCIAL INFORMATION	4
Item 1.	Financial Statements.	4
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	4
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017	5
	Unaudited Condensed Consolidated Statements of Partners' Capital for the nine months ended September 30, 2018 and 2017	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017	7
	Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	59
Item 4.	Controls and Procedures.	59

PART II	OTHER INFORMATION	60
Item 1.	Legal Proceedings.	60
Item 1A.	Risk Factors.	60
Item 6.	Exhibits.	60

SIGNATURES		61

COMMONLY USED OR DEFINED TERMS

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
5.5% Senior Notes	Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
7.5% Senior Notes	Summit Holdings' and Finance Corp.’s 7.5% senior unsecured notes due July 2021 and redeemed in March 2017
5.75% Senior Notes	Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025
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
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
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

Permian Finance	Summit Midstream Permian Finance, LLC
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, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 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) adjustments related to capital reimbursement activity, (vi) unit- based and noncash compensation, (vii) the change in the Deferred Purchase Price Obligation fair value, (viii) early extinguishment of debt expense, (ix) impairments and (x) 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
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 Niobrara	Summit Midstream Niobrara, 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

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
	2018		2017
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	370	$	1,430
Accounts receivable		85,458		72,301
Other current assets		4,360		4,327
Total current assets		90,188		78,058
Property, plant and equipment, net		1,911,630		1,795,129
Intangible assets, net		281,207		301,345
Goodwill		16,211		16,211
Investment in equity method investees		660,254		690,485
Other noncurrent assets		18,566		13,565
Total assets	$	2,978,056	$	2,894,793

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	22,569	$	16,375
Accrued expenses		18,347		12,499
Due to affiliate		13		1,088
Deferred revenue		11,152		4,000
Ad valorem taxes payable		8,223		8,329
Accrued interest		15,285		12,310
Accrued environmental remediation		2,702		3,130
Other current liabilities		10,388		11,258
Total current liabilities		88,679		68,989
Long-term debt		1,175,313		1,051,192
Deferred Purchase Price Obligation		416,718		362,959
Noncurrent deferred revenue		39,624		12,707
Noncurrent accrued environmental remediation		1,182		2,214
Other noncurrent liabilities		5,525		7,063
Total liabilities		1,727,041		1,505,124
Commitments and contingencies (Note 16)

Series A Preferred Units (300,000 units issued and outstanding at September 30, 2018 and December 31, 2017)		300,741		294,426
Common limited partner capital (73,355,775 units issued and outstanding at September 30, 2018 and 73,085,996 units issued and outstanding at December 31, 2017)		913,913		1,056,510
General Partner interests (1,490,999 units issued and outstanding at September 30, 2018 and December 31, 2017)		25,380		27,920
Noncontrolling interest		10,981		10,813
Total partners' capital		1,251,015		1,389,669
Total liabilities and partners' capital	$	2,978,056	$	2,894,793

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	86,427		$	96,070		$	260,373		$	298,884
Natural gas, NGLs and condensate sales		34,017			22,940			92,025			44,655
Other revenues		7,035			5,935			20,584			19,003
Total revenues		127,479			124,945			372,982			362,542
Costs and expenses:
Cost of natural gas and NGLs		26,879			18,177			71,549			36,328
Operation and maintenance		24,382			22,303			73,452			70,011
General and administrative		11,740			13,289			39,666			40,370
Depreciation and amortization		26,743			28,927			80,204			86,184
Transaction costs		—			—			—			119
Loss (gain) on asset sales, net		6			460			(6	)		530
Long-lived asset impairment		1,540			1,290			2,127			1,577
Total costs and expenses		91,290			84,446			266,992			235,119
Other income		58			79			78			214
Interest expense		(14,862	)		(17,614	)		(44,821	)		(51,883	)
Early extinguishment of debt		—			—			—			(22,020	)
Deferred Purchase Price Obligation		37,204			70,499			(53,759	)		54,674
Income before income taxes and (loss) income from equity method investees		58,589			93,463			7,488			108,408
Income tax benefit (expense)		35			(176	)		(88	)		(417	)
(Loss) income from equity method investees		(1,169	)		350			(3,703	)		(3,691	)
Net income	$	57,455		$	93,637		$	3,697		$	104,300
Less:
Net income attributable to noncontrolling interest		25			91			168			282
Net income attributable to SMLP		57,430			93,546			3,529			104,018
Less net income attributable to General Partner, including IDRs		3,279			3,999			6,477			8,442
Net income (loss) attributable to limited partners		54,151			89,547			(2,948	)		95,576
Less net income attributable to Series A Preferred Units		7,125			—			21,375			—
Net income (loss) attributable to common limited partners	$	47,026		$	89,547		$	(24,323	)	$	95,576

Earnings (loss) per limited partner unit:
Common unit – basic	$	0.64		$	1.23		$	(0.33	)	$	1.32
Common unit – diluted	$	0.64		$	1.22		$	(0.33	)	$	1.31

Weighted-average limited partner units outstanding:
Common units – basic		73,356			73,059			73,283			72,583
Common units – diluted		73,756			73,433			73,283			72,901

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

	Partners' capital
	Limited partners
	Common			General Partner			Noncontrolling interest		Total
	(In thousands)
Partners' capital, January 1, 2017	$	1,129,132		$	29,294		$	11,247	$	1,169,673
Net income		95,576			8,442			282		104,300
Distributions to unitholders		(125,052	)		(9,014	)		—		(134,066	)
Unit-based compensation		5,902			—			—		5,902
Tax withholdings on vested SMLP LTIP awards		(2,051	)		—			—		(2,051	)
ATM Program issuances, net of costs		17,251			—			—		17,251
Contribution from General Partner		—			465			—		465
Other		(166	)		—			—		(166	)
Partners' capital, September 30, 2017	$	1,120,592		$	29,187		$	11,529	$	1,161,308

	Partners' capital
	Limited partners
	Series A Preferred Units			Common			General Partner			Noncontrolling interest		Total
	(In thousands)
Partners' capital, December 31, 2017, as reported	$	294,426		$	1,056,510		$	27,920		$	10,813	$	1,389,669
January 1, 2018 impact of Topic 606 day 1 adoption		—			4,130			84			—		4,214
Partners' capital, January 1, 2018		294,426			1,060,640			28,004			10,813		1,393,883
Net income (loss)		21,375			(24,323	)		6,477			168		3,697
Distributions to unitholders		(14,250	)		(126,383	)		(9,101	)		—		(149,734	)
Unit-based compensation		—			5,948			—			—		5,948
Tax withholdings on vested SMLP LTIP awards		—			(1,840	)		—			—		(1,840	)
Other		(810	)		(129	)		—			—		(939	)
Partners' capital, September 30, 2018	$	300,741		$	913,913		$	25,380		$	10,981	$	1,251,015

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine months ended September 30,
	2018			2017
	(In thousands)
Cash flows from operating activities:
Net income	$	3,697		$	104,300
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		79,752			85,732
Amortization of debt issuance costs		3,184			3,117
Deferred Purchase Price Obligation		53,759			(54,674	)
Unit-based and noncash compensation		6,188			5,973
Loss from equity method investees		3,703			3,691
Distributions from equity method investees		26,528			28,715
(Gain) loss on asset sales, net		(6	)		530
Long-lived asset impairment		2,127			1,577
Early extinguishment of debt		—			22,020
Write-off of debt issuance costs		—			302
Changes in operating assets and liabilities:
Accounts receivable		(11,557	)		36,097
Trade accounts payable		(2,991	)		1,200
Accrued expenses		5,848			2,726
Due (to) from affiliate		(1,075	)		256
Deferred revenue, net		5,160			(39,671	)
Ad valorem taxes payable		(106	)		(2,470	)
Accrued interest		2,975			2,700
Accrued environmental remediation, net		(3,060	)		(2,935	)
Other, net		(7,634	)		(2,689	)
Net cash provided by operating activities		166,492			196,497
Cash flows from investing activities:
Capital expenditures		(137,033	)		(86,206	)
Proceeds from asset sale		496			2,300
Contributions to equity method investees		—			(21,581	)
Other, net		(209	)		(579	)
Net cash used in investing activities		(136,746	)		(106,066	)

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Nine months ended September 30,
	2018			2017
	(In thousands)
Cash flows from financing activities:
Distributions to common unitholders		(135,484	)		(134,066	)
Distributions to Series A Preferred unitholders		(14,250	)		—
Borrowings under Revolving Credit Facility		202,000			177,500
Repayments under Revolving Credit Facility		(79,000	)		(319,500	)
Debt issuance costs		(334	)		(15,891	)
Payment of redemption and call premiums on senior notes		—			(17,913	)
Proceeds from ATM Program common unit issuances, net of costs		—			17,251
Contribution from General Partner		—			465
Issuance of senior notes		—			500,000
Tender and redemption of senior notes		—			(300,000	)
Other, net		(3,738	)		(2,794	)
Net cash used in financing activities		(30,806	)		(94,948	)
Net change in cash and cash equivalents		(1,060	)		(4,517	)
Cash and cash equivalents, beginning of period		1,430			7,428
Cash and cash equivalents, end of period	$	370		$	2,911

Supplemental cash flow disclosures:
Cash interest paid	$	44,126		$	47,410
Less capitalized interest		5,536			1,562
Interest paid (net of capitalized interest)	$	38,590		$	45,848

Cash paid for taxes	$	175		$	—

Noncash investing and financing activities
Capital expenditures in trade accounts payable (period-end accruals)	$	20,977		$	13,647
Capital expenditures relating to contributions in aid of construction for Topic 606 day 1 adoption		33,123			—

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

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.

In addition to its approximate 2% general partner interest in SMLP (including the IDRs), Summit Investments has indirect ownership interests in our common units. As of September 30, 2018, Summit Investments beneficially owned 25,854,581 SMLP common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 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, 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:

•

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

•

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;

•

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;

•

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;

•

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 and interstate natural gas transportation pipeline under development in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico.

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 (collectively, 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.

In December 2017, Niobrara G&P, the associated natural gas gathering and processing assets held by Meadowlark Midstream, were contributed to Summit Niobrara, a newly formed entity. Concurrent with this contribution (i) a subsidiary of SMLP purchased the remaining 1% ownership interest in Summit Niobrara held by Summit Epping, LLC; and (ii) 100% of the ownership interests in Summit Niobrara were contributed to Grand River Gathering, LLC (“Grand River”), after which Summit Niobrara became a wholly owned subsidiary of Grand River.

Summit Marketing 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.

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 the annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments, including normal recurring adjustments, which are necessary to fairly present the unaudited condensed consolidated balance sheet as of September 30, 2018, the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017 and the unaudited condensed consolidated statements of partners’ capital and cash flows for the nine months ended September 30, 2018 and 2017. The balance sheet at December 31, 2017 included herein was derived from our audited financial statements, but does not include all disclosures required by GAAP. See Notes 2 and 3 for the impact relating to the adoption of the new revenue standard. 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, 2017, as filed with the SEC on February 26, 2018 (the "2017 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

Except for the changes below, there have been no changes to our significant accounting policies since December 31, 2017.

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. 2014-09 Revenue from Contracts with Customers (“Topic 606”). We adopted Topic 606 with a date of initial application of January 1, 2018. We applied Topic 606 by recognizing the cumulative effect of initially applying Topic 606 as an adjustment to the opening balance of partners’ capital at January 1, 2018. The comparative information has not been adjusted and is reported under the accounting standards in effect for those periods.

For contracts where we perform gathering services and earn a per-unit fee which is recognized at a point in time, revenue is recognized over time as the service is performed and results in revenue recognition materially consistent with historical GAAP. In addition, our contracts generally contain forms of variable consideration, which will likely be constrained as the volumes are susceptible to factors outside of our control and influence. As a result of applying the constraint guidance, timing of revenue recognition will be materially consistent with historical GAAP.

Prior to the adoption of Topic 606, contributions in aid of construction were recognized as a reduction to our cost basis of property, plant and equipment and facility fees were recognized as revenue when the amounts were billed. Upon adoption of Topic 606, the contributions in aid of construction amounts previously received were capitalized to property, plant and equipment, net of any accumulated depreciation, and will be depreciated over the remaining useful lives. Any future contributions in aid of construction will be recognized as revenue over the remaining term of the respective contract in accordance with Topic 606. Additionally, facility fees will be deferred and recognized over the contract term.

There are certain percent-of-proceeds contracts within our Williston Basin reportable segment where we previously recognized revenue for services provided to producers in gathering services and related fees. Such amounts which were previously presented gross in gathering services and related fees are presented net within cost of natural gas and NGLs. This change did not have any impact on our net income (loss), cash flows, or the amount we present as segment adjusted EBITDA.

For contracts containing MVC arrangements with banking mechanisms we previously deferred revenue. Under Topic 606, the recognition of revenue was accelerated. This acceleration totaled $16.7 million and is included in the Topic 606 day one adjustment amounts below in deferred revenue.

The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of Topic 606 was as follows:

	Balance at December 31, 2017		Adjustments Due to Topic 606		Balance at January 1, 2018
	(In thousands)
Assets
Property, plant and equipment, net	$	1,795,129	$	33,123	$	1,828,252

Liabilities
Deferred revenue, current		4,000		6,088		10,088
Deferred revenue, noncurrent		12,707		22,821		35,528

Partners' Capital (1)		1,084,430		4,214		1,088,644

________

(1) Includes common limited partner capital and general partner interests.

Impact on financial statements

The following tables summarize the impact of Topic 606 adoption on our unaudited condensed consolidated financial statements.

Unaudited condensed consolidated balance sheet

	September 30, 2018
	As Reported		Balances Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
	(In thousands)
Assets
Accounts receivable	$	85,458	$	76,656	$	8,802
Other noncurrent assets		18,566		12,566		6,000
Property, plant and equipment, net		1,911,630		1,874,388		37,242

Liabilities
Deferred revenue, current		11,152		4,071		7,081
Deferred revenue, noncurrent		39,624		10,065		29,559

Partners' Capital (1)		939,293		923,889		15,404

________

(1) Includes common limited partner capital and general partner interests.

Unaudited condensed consolidated statement of operations

	Three months ended September 30, 2018
	As Reported		Balances Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
	(In thousands)
Revenues
Gathering services and related fees	$	86,427	$	83,351	$	3,076
Costs and expenses
Cost of natural gas and NGLs		26,879		30,307		(3,428	)
Depreciation and amortization		26,743		26,373		370

	Nine months ended September 30, 2018
	As Reported		Balances Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
	(In thousands)
Revenues
Gathering services and related fees	$	260,373	$	255,546	$	4,827
Costs and expenses
Cost of natural gas and NGLs		71,549		81,468		(9,919	)
Depreciation and amortization		80,204		79,219		985

Unaudited condensed consolidated statement of cash flows

	Nine months ended September 30, 2018
	As Reported			Balances Without Adoption of Topic 606			Effect of Change Increase / (Decrease)
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	3,697		$	(10,064	)	$	13,761
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		79,752			78,767			985
Changes in operating assets and liabilities:
Accounts receivable		(11,557	)		(2,755	)		(8,802	)
Other, net		(7,634	)		(1,634	)		(6,000	)
Deferred revenue, net		5,160			5,104			56

•

ASU No. 2017-04 Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by, among other things, eliminating step two from the goodwill impairment test. ASU 2017-04 is effective for public companies for fiscal years beginning after December 15, 2019 and it specifies the amendments in ASU 2017-04 should be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We adopted the provisions of ASU 2017-04 effective January 1, 2018. The adoption of this standard had no impact on our consolidated financial statements.

Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncements as of September 30, 2018:

•

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. 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 will adopt its provisions effective January 1, 2019. We expect to utilize certain practical expedients including (i) not being required to reassess whether any expired or existing contracts are or contain leases; (ii) not being required to reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will be classified as finance leases); and (iii) not being required to reassess initial direct costs for any existing leases.

•

ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. Upon adoption of Topic 842, an entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date the entity adopts Topic 842. We expect to adopt the optional transition practical expedient of ASU 2018-01 effective January 1, 2019.

•

ASU No. 2018-13 Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU 2018-13 removes certain existing disclosure

requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. We are currently evaluating the provisions of ASU 2018-13 to determine its impact on our financial statements and related disclosures and will adopt its provisions effective January 1, 2020.

3. REVENUE

The majority of our revenue is derived from long-term, fee-based contracts with original terms of up to 25 years. We account for revenue in accordance with Topic 606, which we adopted on January 1, 2018, using the modified retrospective method. See Note 2 for further discussion of the adoption, including the impact on our unaudited condensed consolidated financial statements.

We recognize revenue earned from fee-based gathering, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin reporting segment from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under Topic 606, these gathering fee contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain DFW Midstream customers to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from our gathering services at Grand River. Revenues from the sale of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in other revenues.

The transaction price in our contracts is primarily based on the volume of natural gas, crude oil or produced water transferred by our gathering systems to the customer’s agreed upon delivery point multiplied by the contractual rate. For contracts that include MVCs, variable consideration up to the MVC will be included in the transaction price. For contracts that do not include MVCs, we do not estimate variable consideration because the performance obligations are completed and settled on a daily basis. For contracts containing noncash consideration such as fuel received in-kind, we measure the transaction price at the point of sale when the volume, mix and market price of the commodities are known.

We have contracts with MVCs that are variable and constrained. Contracts with MVCs are reviewed on a quarterly basis and adjustments to those estimates are made during each respective reporting period, if necessary.

The transaction price is allocated if the contract contains more than one performance obligation such as contracts that include MVCs. The transaction price allocated is based on the MVC for the applicable measurement period.

Performance obligations. The majority of our contracts have a single performance obligation which is either to provide gathering services (an integrated service) or sell natural gas, NGLs and condensate, which are both satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. We also have certain contracts with multiple performance obligations. They include an option for the customer to acquire additional services such as contracts containing MVCs. These performance obligations would also be satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. In these instances, we allocate the contract’s transaction price to each performance obligation using our best estimate of the standalone selling price of each service in the contract.

Performance obligations for gathering services are generally satisfied over time. We utilize either an output method (i.e., measure of progress) for guaranteed, stand-ready service contracts or an asset / system delivery time estimate for non-guaranteed, as-available service contracts.

Performance obligations for the sale of natural gas, NGLs and condensate are satisfied at a point in time. There are no significant judgments for these transactions because the customer obtains control based on an agreed upon delivery point.

Certain of our gathering and/or processing agreements provide for monthly, annual or multi-year MVCs. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.

We recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.

Our services are typically billed on a monthly basis and we do not offer extended payment terms. We do not have contracts with financing components.

The following table presents estimated revenue expected to be recognized during the remainder of 2018 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.

We applied the practical expedient in paragraph 606-10-50-14 of Topic 606 for certain arrangements that we consider optional purchases (i.e., there is no enforceable obligation for the customer to make purchases) and those amounts are excluded from the table.

	2018		2019		2020		2021		2022		Thereafter
	(In thousands)
Gathering services and related fees	$	84,164	$	127,743	$	122,429	$	102,777	$	83,648	$	174,825

Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. For more detailed information about reportable segments, see Note 4.

	Reportable Segments
	Three months ended September 30, 2018
	Utica Shale		Williston Basin		Piceance / DJ Basins		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products/services lines
Gathering services and related fees	$	7,974	$	18,020	$	36,743	$	18,318	$	7,150	$	88,205	$	(1,778	)	$	86,427
Natural gas, NGLs and condensate sales		—		7,953		3,650		789		—		12,392		21,625			34,017
Other revenues		—		3,037		2,072		1,913		—		7,022		13			7,035
Total	$	7,974	$	29,010	$	42,465	$	21,020	$	7,150	$	107,619	$	19,860		$	127,479

	Reportable Segments
	Nine months ended September 30, 2018
	Utica Shale		Williston Basin		Piceance / DJ Basins		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products/services lines
Gathering services and related fees	$	28,437	$	58,792	$	108,207	$	46,035	$	23,025	$	264,496	$	(4,123	)	$	260,373
Natural gas, NGLs and condensate sales		—		23,149		12,650		1,715		—		37,514		54,511			92,025
Other revenues		—		8,909		6,187		5,595		—		20,691		(107	)		20,584
Total	$	28,437	$	90,850	$	127,044	$	53,345	$	23,025	$	322,701	$	50,281		$	372,982

Contract balances. Contract assets relate to our rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from our customers and unbilled activity associated with contributions in aid of construction. Contract assets are transferred to trade receivables when the rights become unconditional. The following table provides information about contract assets from contracts with customers:

	September 30, 2018
	(In thousands)
Contract assets, December 31, 2017	$	—
Net impact of Topic 606 day 1 adoption		3,514
Additions		14,906
Transfers out		(7,169	)
Contract assets, September 30, 2018	$	11,251

As of September 30, 2018, receivables with customers totaled $70.8 million and contract assets totaled $11.3 million which were included in the accounts receivable caption on the unaudited condensed consolidated balance sheet. In addition, long-term contract assets of $6.0 million, which are excluded from the table above, were included in the other noncurrent assets caption on the unaudited condensed consolidated balance sheet.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. We recognize contract liabilities under these arrangements in revenue over the contract period. For the three and nine months ended September 30, 2018, we recognized $2.8 million and $7.8 million of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. See Note 9 for additional details.

4. SEGMENT INFORMATION

As of September 30, 2018, 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 Polar and Divide, Tioga Midstream and Bison 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.

The Ohio Gathering reportable segment includes our investment in OGC and OCC (see Note 8). 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 8). 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) not allocated to our reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, natural gas and crude oil marketing services, and transaction costs.

Assets by reportable segment follow.

	September 30, 2018			December 31, 2017
	(In thousands)
Assets:
Utica Shale	$	209,105		$	212,311
Ohio Gathering		660,254			690,485
Williston Basin		529,370			512,860
Piceance/DJ Basins		839,166			798,722
Barnett Shale		380,161			383,306
Marcellus Shale		210,509			217,362
Total reportable segment assets		2,828,565			2,815,046
Corporate and Other		152,375			79,996
Eliminations		(2,884	)		(249	)
Total assets	$	2,978,056		$	2,894,793

Revenues by reportable segment follow.

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands)
Revenues (1):
Utica Shale	$	7,974		$	9,727		$	28,437		$	28,979
Williston Basin		29,010			27,821			90,850			123,820
Piceance/DJ Basins		42,465			53,875			127,044			122,446
Barnett Shale		21,020			16,694			53,345			55,340
Marcellus Shale		7,150			8,160			23,025			22,429
Total reportable segments revenue		107,619			116,277			322,701			353,014
Corporate and Other		23,636			11,816			57,234			14,964
Eliminations		(3,776	)		(3,148	)		(6,953	)		(5,436	)
Total revenues	$	127,479		$	124,945		$	372,982		$	362,542

(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 September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Percentage of total revenues (1)(2):
Counterparty A - Piceance/DJ Basins		11	%		17	%		11	%	*
Counterparty B - Barnett Shale		12	%	*				10	%	*
Counterparty C - Williston Basin	*			*			*				16	%

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

(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.

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Depreciation and amortization (1):
Utica Shale	$	1,887	$	1,818	$	5,773	$	5,213
Williston Basin		5,672		8,405		16,903		25,171
Piceance/DJ Basins		12,512		12,199		37,517		36,635
Barnett Shale (2)		3,760		3,735		11,276		11,259
Marcellus Shale		2,273		2,268		6,819		6,794
Total reportable segment depreciation and amortization		26,104		28,425		78,288		85,072
Corporate and Other		488		352		1,464		660
Total depreciation and amortization	$	26,592	$	28,777	$	79,752	$	85,732

(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.

	Nine months ended September 30,
	2018		2017
	(In thousands)
Cash paid for capital expenditures (1):
Utica Shale	$	3,922	$	21,425
Williston Basin		18,463		13,735
Piceance/DJ Basins		44,166		17,902
Barnett Shale		914		119
Marcellus Shale		557		628
Total reportable segment capital expenditures		68,022		53,809
Corporate and Other		69,011		32,397
Total cash paid for capital expenditures	$	137,033	$	86,206

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

During the nine months ended September 30, 2018, Corporate included cash paid of $2.1 million for corporate purposes; the remainder represents capital expenditures 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 (as defined below), (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) change in the Deferred Purchase Price Obligation fair value, (viii) early extinguishment of debt expense, (ix) impairments and (x) 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.

Segment adjusted EBITDA by reportable segment follows.

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	6,521	$	8,412	$	24,459	$	25,857
Ohio Gathering		10,171		10,522		29,583		29,201
Williston Basin		19,849		16,212		54,849		51,176
Piceance/DJ Basins		29,831		30,008		86,739		86,256
Barnett Shale		10,818		10,838		31,770		35,924
Marcellus Shale		5,550		6,682		18,769		17,775
Total of reportable segments' measures of profit	$	82,740	$	82,674	$	246,169	$	246,189

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

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands)
Reconciliation of income before income taxes and (loss) income from equity method investees to total of reportable segments' measures of profit:
Income before income taxes and (loss) income from equity method investees	$	58,589		$	93,463		$	7,488		$	108,408
Add:
Corporate and Other		9,324			9,197			28,949			28,725
Interest expense		14,862			17,614			44,821			51,883
Early extinguishment of debt		—			—			—			22,020
Deferred Purchase Price Obligation		(37,204	)		(70,499	)		53,759			(54,674	)
Depreciation and amortization		26,592			28,777			79,752			85,732
Proportional adjusted EBITDA for equity method investees		10,171			10,522			29,583			29,201
Adjustments related to MVC shortfall payments		(2,999	)		(10,124	)		(6,541	)		(33,186	)
Adjustments related to capital reimbursement activity		(106	)		—			49			—
Unit-based and noncash compensation		1,965			1,974			6,188			5,973
Loss (gain) on asset sales, net		6			460			(6	)		530
Long-lived asset impairment		1,540			1,290			2,127			1,577
Total of reportable segments' measures of profit	$	82,740		$	82,674		$	246,169		$	246,189

For the three and nine months ended September 30, 2017, we included 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 or multi-year MVC shortfall payments. With respect to the impact of a net change in deferred revenue for MVC shortfall payments, we treated increases in deferred revenue balances as a favorable adjustment to segment adjusted EBITDA, while decreases in deferred revenue balances were treated as an unfavorable adjustment to segment adjusted EBITDA. We also included a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognized the shortfall payment.

For the three and nine months ended September 30, 2018, in accordance with Topic 606, adjustments related to MVC shortfall payments are recognized in gathering services and related fees (see Note 3).

In accordance with Topic 606, contributions in aid of construction are recognized over the remaining term of the respective contract. We include adjustments related to capital reimbursement activity in our calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction.

Adjustments related to MVC shortfall payments by reportable segment follow.

	Three months ended September 30, 2018
	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	$	—	$	—	$	—		$	—
Expected MVC shortfall adjustments		2,032		—		(5,031	)		(2,999	)
Total adjustments related to MVC shortfall payments	$	2,032	$	—	$	(5,031	)	$	(2,999	)

	Three months ended September 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	$	—	$	—		$	—	$	—
Expected MVC shortfall adjustments		1,982		(12,200	)		94		(10,124	)
Total adjustments related to MVC shortfall payments	$	1,982	$	(12,200	)	$	94	$	(10,124	)

	Nine months ended September 30, 2018
	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	$	—		$	—		$	—		$	—
Expected MVC shortfall adjustments		(1,354	)		(93	)		(5,094	)		(6,541	)
Total adjustments related to MVC shortfall payments	$	(1,354	)	$	(93	)	$	(5,094	)	$	(6,541	)

	Nine months ended September 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 adjustments		5,946			867			(328	)		6,485
Total adjustments related to MVC shortfall payments	$	(31,747	)	$	(1,111	)	$	(328	)	$	(33,186	)

5. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	September 30, 2018		December 31, 2017
	(In thousands)
Gathering and processing systems and related equipment	$	2,031,540	$	1,973,722
Construction in progress		194,472		78,850
Land and line fill		11,747		11,735
Other		42,286		40,262
Total		2,280,045		2,104,569
Less accumulated depreciation		368,415		309,440
Property, plant and equipment, net	$	1,911,630	$	1,795,129

Depreciation expense and capitalized interest follow.

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Depreciation expense	$	18,567	$	18,837	$	55,781	$	55,935
Capitalized interest		2,451		644		5,536		1,562

6. AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT

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

	September 30, 2018
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(13,517	)	$	10,678
Contract intangibles		278,448		(137,426	)		141,022
Rights-of-way		165,445		(35,938	)		129,507
Total intangible assets	$	468,088	$	(186,881	)	$	281,207

Unfavorable gas gathering contract	$	10,962	$	(10,692	)	$	270

	December 31, 2017
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(12,350	)	$	11,845
Contract intangibles		278,448		(117,821	)		160,627
Rights-of-way		159,986		(31,113	)		128,873
Total intangible assets	$	462,629	$	(161,284	)	$	301,345

Unfavorable gas gathering contract	$	10,962	$	(9,074	)	$	1,888

We recognized amortization expense in other revenues as follows:

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(389	)	$	(390	)	$	(1,166	)	$	(1,167	)
Amortization expense – unfavorable gas gathering contract		540			540			1,618			1,619

We recognized amortization expense in costs and expenses as follows:

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Amortization expense – contract intangibles	$	6,535	$	8,550	$	19,605	$	25,652
Amortization expense – rights-of-way		1,641		1,540		4,818		4,597

The estimated aggregate annual amortization expected to be recognized for the remainder of 2018 and each of the four succeeding fiscal years follows.

	Intangible assets		Unfavorable gas gathering contract
	(In thousands)
2018	$	8,562	$	270
2019		33,321		—
2020		33,145		—
2021		29,453		—
2022		26,386		—

7. GOODWILL

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

We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2018, using a combination of the income and market approaches. We determined that the fair value of the Mountaineer Midstream reporting unit substantially exceeded its carrying value, including goodwill; as such, there have been no impairments of goodwill during the nine months ended September 30, 2018.

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 2017 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.

8. 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 September 2018, 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 third quarter of 2018 because the information was available to us. We recorded our 40% share of the impairment loss, or $1.8 million, in September 2018 in loss from equity method investees in the unaudited condensed consolidated statements of operations.

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

Investment in equity method investees, September 30, 2018	$	660,254
September cash distributions		2,912
Impairment loss		1,837
Basis difference		(120,170	)
Investment in equity method investees, net of basis difference, August 31, 2018	$	544,833

For the three and nine months ended September 30, 2018, there were no contributions to Ohio Gathering.

Summarized statements of operations information for OGC and OCC follow (amounts represent 100% of investee financial information). Results include gross asset impairments of $4.6 million and $16.9 million for the three and nine months ending September 30, 2018 and $8.7 million for the three and nine months ending September 30, 2017.

	Three months ended August 31, 2018					Three months ended August 31, 2017
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	37,180	$	2,465		$	35,144	$	1,814
Total operating expenses		31,751		2,323			25,720		1,877
Net income (loss)		5,429		(5	)		9,424		(204	)

	Nine months ended August 31, 2018				Nine months ended August 31, 2017
	OGC		OCC		OGC		OCC
	(In thousands)
Total revenues	$	106,263	$	7,024	$	103,302	$	5,871
Total operating expenses		94,044		6,422		86,046		6,186
Net income (loss)		12,213		116		17,258		(1,396	)

9. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

	Utica Shale		Williston Basin		Piceance/DJ Basins		Barnett Shale		Marcellus Shale		Total current
	(In thousands)
Current deferred revenue, December 31, 2017, as reported	$	—	$	—	$	4,000	$	—	$	—	$	4,000
Net impact of Topic 606 day 1 adoption		18		1,017		3,396		1,619		38		6,088
Current deferred revenue, January 1, 2018		18		1,017		7,396		1,619		38		10,088
Additions		14		1,367		16,846		1,236		63		19,526
Less revenue recognized		14		985		16,186		1,214		63		18,462
Current deferred revenue, September 30, 2018	$	18	$	1,399	$	8,056	$	1,641	$	38	$	11,152

A rollforward of noncurrent deferred revenue follows.

	Utica Shale		Williston Basin		Piceance/DJ Basins		Barnett Shale		Marcellus Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, December 31, 2017, as reported	$	—	$	—	$	12,707	$	—	$	—	$	12,707
Net impact of Topic 606 day 1 adoption		39		4,215		10,017		8,217		333		22,821
Noncurrent deferred revenue, January 1, 2018		39		4,215		22,724		8,217		333		35,528
Additions		—		1,851		9,014		2,323		—		13,188
Less reclassification to current deferred revenue		14		1,296		6,483		1,236		63		9,092
Noncurrent deferred revenue, September 30, 2018	$	25	$	4,770	$	25,255	$	9,304	$	270	$	39,624

10. DEBT

Debt consisted of the following:

	September 30, 2018			December 31, 2017
	(In thousands)
Summit Holdings' variable rate senior secured Revolving Credit Facility (4.50% at September 30, 2018 and 4.07% at December 31, 2017) due May 2022	$	384,000		$	261,000
Summit Holdings' 5.5% senior unsecured notes due August 2022		300,000			300,000
Less unamortized debt issuance costs (1)		(2,530	)		(2,910	)
Summit Holdings' 5.75% senior unsecured notes due April 2025		500,000			500,000
Less unamortized debt issuance costs (1)		(6,157	)		(6,898	)
Total long-term debt	$	1,175,313		$	1,051,192

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

Revolving Credit Facility. Summit Holdings has a senior secured revolving credit facility that allows for revolving loans, letters of credit and swing line loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, Summit Niobrara, OpCo, Summit Utica, Meadowlark Midstream, Tioga Midstream and SMLP fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of, the indebtedness outstanding under the Revolving Credit Facility.

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 September 30, 2018, the applicable margin under LIBOR borrowings was 2.25% and the interest rate was 4.50%. The unused portion of the Revolving Credit Facility totaled $866.0 million (subject to a commitment fee of 0.375%).

As of September 30, 2018, we had $9.2 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 and during the nine months ended September 30, 2018, we were in compliance with the Revolving Credit Facility's covenants. There were no defaults or events of default during the nine months ended September 30, 2018.

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

In February 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 in the 2017 Annual Report. References to the "Senior Notes," refer collectively to the 5.5% Senior Notes and the 5.75% Senior Notes.

Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance and Summit Niobrara (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.

As of and during the nine months ended September 30, 2018, we were in compliance with the covenants governing our Senior Notes. There were no defaults or events of default during the nine months ended September 30, 2018.

11. 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 counterparties accounted for 46% of total accounts receivable as of September 30, 2018, compared with 44% as of December 31, 2017.

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 recurring Level 3 measurement in the fair value hierarchy because our assumptions and judgments are not observable from objective sources (see Note 17).

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, 2018	$	362,959
Change in fair value		53,759
Level 3 liability, September 30, 2018	$	416,718

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

	September 30, 2018				December 31, 2017
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings 5.5% Senior Notes ($300.0 million principal)	$	297,470	$	300,000	$	297,090	$	301,750
Summit Holdings 5.75% Senior Notes ($500.0 million principal)		493,843		481,250		493,102		501,667

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 September 30, 2018 and December 31, 2017. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

12. PARTNERS' CAPITAL

A rollforward of the number of common limited partner and General Partner units follows.

	Limited partners
	Series A Preferred Units		Common		General Partner
Units, January 1, 2018		300,000		73,085,996		1,490,999
Net units issued under the SMLP LTIP		—		269,779		—
Units, September 30, 2018		300,000		73,355,775		1,490,999

At-the-market Program. In 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 (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 and nine months ended September 30, 2018, there were no transactions under the ATM Program. 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 September 30, 2018, we have the capacity to issue additional common units under the ATM Program up to an aggregate $132.3 million.

Series A Preferred Units. In 2017, we issued 300,000 Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) representing limited partner interests in the Partnership at a price to the public of $1,000 per unit as described in the 2017 Annual Report.

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.

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

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Per-unit distributions to unitholders	$	0.575	$	0.575	$	1.725	$	1.725

On October 25, 2018, the Board of Directors of our General Partner declared a distribution of $0.575 per unit for the quarterly period ended September 30, 2018. This distribution, which totaled $45.2 million, will be paid on November 14, 2018 to unitholders of record at the close of business on November 7, 2018.

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 nine months ended September 30 follow.

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
IDR payments	$	2,136	$	2,127	$	6,400	$	6,333

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.

13. EARNINGS PER UNIT

The following table details the components of EPU.

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018			2017
	(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net income (loss) among limited partner interests:
Net income (loss) attributable to limited partners	$	54,151	$	89,547	$	(2,948	)	$	95,576
Less net income attributable to Series A Preferred Units		7,125		—		21,375			—
Net income (loss) attributable to common limited partners	$	47,026	$	89,547	$	(24,323	)	$	95,576

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic		73,356		73,059		73,283			72,583
Effect of nonvested phantom units		400		374		—			318
Weighted-average common units outstanding – diluted		73,756		73,433		73,283			72,901

Earnings (loss) per limited partner unit:
Common unit – basic	$	0.64	$	1.23	$	(0.33	)	$	1.32
Common unit – diluted	$	0.64	$	1.22	$	(0.33	)	$	1.31

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		1		—		2			55

14. 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 2018, we granted 515,358 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 $15.25 and vest ratably over a three-year period.

•

Also in March 2018, 328,388 phantom units vested.

•

As of September 30, 2018, approximately 3.2 million common units remained available for future issuance under the SMLP LTIP.

15. RELATED-PARTY TRANSACTIONS

Acquisitions. See Notes 11 and 16 of the 2017 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.

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

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Operation and maintenance expense	$	7,161	$	6,792	$	21,898	$	20,404
General and administrative expense		7,220		6,840		22,818		23,030

16. 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 September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Rent expense	$	957	$	1,009	$	2,935	$	2,811

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 the 2017 Annual Report, in 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.

A rollforward of the aggregate accrued environmental remediation liabilities follows.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2018	$	5,344
Payments made		(3,060	)
Additional accruals		1,600
Accrued environmental remediation, September 30, 2018	$	3,884

As of September 30, 2018, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to September 30, 2019. 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.

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.

As described in the 2017 Annual Report, in 2015 and 2016, the U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, our General Partner and Meadowlark Midstream requesting certain materials related to the incident. SMLP has continued to exchange information with the DOJ and is cooperating with the investigation. 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.

17. ACQUISITIONS AND DROP DOWN TRANSACTIONS

2016 Drop Down. In 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 present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid. As of September 30, 2018, Remaining Consideration was estimated to be $470.9 million and the net present value, as recognized on the consolidated balance sheet, was $416.7 million, using a discount rate of 8.50%. 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.

We currently expect that the Deferred Purchase Price Obligation will be financed with a combination of (i) net proceeds from the issuance of equity securities 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.

18. 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 10).

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.

Condensed Consolidating Balance Sheets. Balance sheets as of September 30, 2018 and December 31, 2017 follow.

	September 30, 2018
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	29	$	3	$	330	$	8	$	—		$	370
Accounts receivable		22		—		74,766		10,670		—			85,458
Other current assets		843		—		2,922		595		—			4,360
Due from affiliate		—		—		513,867		68,121		(581,988	)		—
Total current assets		894		3		591,885		79,394		(581,988	)		90,188
Property, plant and equipment, net		5,134		—		1,563,950		342,546		—			1,911,630
Intangible assets, net		—		—		255,317		25,890		—			281,207
Goodwill		—		—		16,211		—		—			16,211
Investment in equity method investees		—		—		—		660,254		—			660,254
Other noncurrent assets		3,320		9,184		6,062		—		—			18,566
Investment in subsidiaries		2,082,686		3,432,198		—		—		(5,514,884	)		—
Total assets	$	2,092,034	$	3,441,385	$	2,433,425	$	1,108,084	$	(6,096,872	)	$	2,978,056

Liabilities and Partners' Capital
Trade accounts payable	$	219	$	—	$	18,523	$	3,827	$	—		$	22,569
Accrued expenses		725		—		16,051		1,571		—			18,347
Due to affiliate		413,900		168,101		—		—		(581,988	)		13
Deferred revenue		—		—		10,716		436		—			11,152
Ad valorem taxes payable		14		—		7,802		407		—			8,223
Accrued interest		—		15,285		—		—		—			15,285
Accrued environmental remediation		—		—		—		2,702		—			2,702
Other current liabilities		5,386		—		4,488		514		—			10,388
Total current liabilities		420,244		183,386		57,580		9,457		(581,988	)		88,679
Long-term debt		—		1,175,313		—		—		—			1,175,313
Deferred Purchase Price Obligation		416,718		—		—		—		—			416,718
Noncurrent deferred revenue		—		—		37,802		1,822		—			39,624
Noncurrent accrued environmental remediation		—		—		—		1,182		—			1,182
Other noncurrent liabilities		4,057		—		1,437		31		—			5,525
Total liabilities		841,019		1,358,699		96,819		12,492		(581,988	)		1,727,041

Total partners' capital		1,251,015		2,082,686		2,336,606		1,095,592		(5,514,884	)		1,251,015
Total liabilities and partners' capital	$	2,092,034	$	3,441,385	$	2,433,425	$	1,108,084	$	(6,096,872	)	$	2,978,056

	December 31, 2017
	SMLP		Co-Issuers		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Assets
Cash and cash equivalents	$	126	$	75	$	1,138	$	91	$	—		$	1,430
Accounts receivable		22		—		65,842		6,437		—			72,301
Other current assets		1,188		—		2,697		442		—			4,327
Due from affiliate		—		—		493,067		22,030		(515,097	)		—
Total current assets		1,336		75		562,744		29,000		(515,097	)		78,058
Property, plant and equipment, net		4,206		—		1,442,333		348,590		—			1,795,129
Intangible assets, net		—		—		278,958		22,387		—			301,345
Goodwill		—		—		16,211		—		—			16,211
Investment in equity method investees		—		—		—		690,485		—			690,485
Other noncurrent assets		2,547		10,913		105		—		—			13,565
Investment in subsidiaries		2,019,700		3,324,464		—		—		(5,344,164	)		—
Total assets	$	2,027,789	$	3,335,452	$	2,300,351	$	1,090,462	$	(5,859,261	)	$	2,894,793

Liabilities and Partners' Capital
Trade accounts payable	$	209	$	—	$	11,283	$	4,883	$	—		$	16,375
Accrued expenses		928		—		10,592		979		—			12,499
Due to affiliate		263,935		252,250		—		—		(515,097	)		1,088
Deferred revenue		—		—		4,000		—		—			4,000
Ad valorem taxes payable		—		—		7,809		520		—			8,329
Accrued interest		—		12,310		—		—		—			12,310
Accrued environmental remediation		—		—		—		3,130		—			3,130
Other current liabilities		6,395		—		4,385		478		—			11,258
Total current liabilities		271,467		264,560		38,069		9,990		(515,097	)		68,989
Long-term debt		—		1,051,192		—		—		—			1,051,192
Deferred Purchase Price Obligation		362,959		—		—		—		—			362,959
Deferred revenue		—		—		12,707		—		—			12,707
Noncurrent accrued environmental remediation		—		—		—		2,214		—			2,214
Other noncurrent liabilities		3,694		—		3,293		76		—			7,063
Total liabilities		638,120		1,315,752		54,069		12,280		(515,097	)		1,505,124

Total partners' capital		1,389,669		2,019,700		2,246,282		1,078,182		(5,344,164	)		1,389,669
Total liabilities and partners' capital	$	2,027,789	$	3,335,452	$	2,300,351	$	1,090,462	$	(5,859,261	)	$	2,894,793

Condensed Consolidating Statements of Operations. For the purposes of the following condensed consolidating statements of operations, we allocate general and administrative expenses recognized at the SMLP parent to the Guarantor Subsidiaries and Non-Guarantor Subsidiaries to reflect what those entities' results would have been had they operated on a stand-alone basis. Statements of operations for the three and nine months ended September 30, 2018 and 2017 follow.

	Three months ended September 30, 2018
	SMLP		Co-Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—	$	—		$	73,014	$	13,413		$	—		$	86,427
Natural gas, NGLs and condensate sales		—		—			34,017		—			—			34,017
Other revenues		—		—			6,806		229			—			7,035
Total revenues		—		—			113,837		13,642			—			127,479
Costs and expenses:
Cost of natural gas and NGLs		—		—			26,879		—			—			26,879
Operation and maintenance		—		—			21,721		2,661			—			24,382
General and administrative		—		—			10,535		1,205			—			11,740
Depreciation and amortization		429		—			22,863		3,451			—			26,743
Loss on asset sales, net		—		—			1		5			—			6
Long-lived asset impairment		—		—			275		1,265			—			1,540
Total costs and expenses		429		—			82,274		8,587			—			91,290
Other income		58		—			—		—			—			58
Interest expense		—		(14,862	)		—		—			—			(14,862	)
Deferred Purchase Price Obligation		37,204		—			—		—			—			37,204
Income (loss) before income taxes and loss from equity method investees		36,833		(14,862	)		31,563		5,055			—			58,589
Income tax benefit		35		—			—		—			—			35
Loss from equity method investees		—		—			—		(1,169	)		—			(1,169	)
Equity in earnings of consolidated subsidiaries		20,587		35,449			—		—			(56,036	)		—
Net income	$	57,455	$	20,587		$	31,563	$	3,886		$	(56,036	)	$	57,455

	Three months ended September 30, 2017
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	82,152		$	13,918	$	—		$	96,070
Natural gas, NGLs and condensate sales		—			—			22,940			—		—			22,940
Other revenues		—			—			5,877			58		—			5,935
Total revenues		—			—			110,969			13,976		—			124,945
Costs and expenses:
Cost of natural gas and NGLs		—			—			18,177			—		—			18,177
Operation and maintenance		—			—			20,217			2,086		—			22,303
General and administrative		—			—			11,919			1,370		—			13,289
Depreciation and amortization		352			—			25,247			3,328		—			28,927
Transaction costs		—			—			—			—		—			—
(Gain) loss on asset sales, net		—			—			(82	)		542		—			460
Long-lived asset impairment		—			—			696			594		—			1,290
Total costs and expenses		352			—			76,174			7,920		—			84,446
Other income		79			—			—			—		—			79
Interest expense		—			(17,614	)		—			—		—			(17,614	)
Deferred Purchase Price Obligation		70,499			—			—			—		—			70,499
Income (loss) before income taxes and income from equity method investees		70,226			(17,614	)		34,795			6,056		—			93,463
Income tax expense		(176	)		—			—			—		—			(176	)
Income from equity method investees		—			—			—			350		—			350
Equity in earnings of consolidated subsidiaries		23,587			41,201			—			—		(64,788	)		—
Net income	$	93,637		$	23,587		$	34,795		$	6,406	$	(64,788	)	$	93,637

	Nine months ended September 30, 2018
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	216,371		$	44,002		$	—		$	260,373
Natural gas, NGLs and condensate sales		—			—			92,025			—			—			92,025
Other revenues		—			—			20,042			542			—			20,584
Total revenues		—			—			328,438			44,544			—			372,982
Costs and expenses:
Cost of natural gas and NGLs		—			—			71,549			—			—			71,549
Operation and maintenance		—			—			66,095			7,357			—			73,452
General and administrative		—			—			34,786			4,880			—			39,666
Depreciation and amortization		1,305			—			68,500			10,399			—			80,204
(Gain) loss on asset sales, net		—			—			(74	)		68			—			(6	)
Long-lived asset impairment		—			—			862			1,265			—			2,127
Total costs and expenses		1,305			—			241,718			23,969			—			266,992
Other income		78			—			—			—			—			78
Interest expense		—			(44,821	)		—			—			—			(44,821	)
Deferred Purchase Price Obligation		(53,759	)		—			—			—			—			(53,759	)
(Loss) income before income taxes and loss from equity method investees		(54,986	)		(44,821	)		86,720			20,575			—			7,488
Income tax expense		(88	)		—			—			—			—			(88	)
Loss from equity method investees		—			—			—			(3,703	)		—			(3,703	)
Equity in earnings of consolidated subsidiaries		58,771			103,592			—			—			(162,363	)		—
Net income	$	3,697		$	58,771		$	86,720		$	16,872		$	(162,363	)	$	3,697

	Nine months ended September 30, 2017
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Revenues:
Gathering services and related fees	$	—		$	—		$	252,344		$	46,540		$	—		$	298,884
Natural gas, NGLs and condensate sales		—			—			44,655			—			—			44,655
Other revenues		—			—			18,809			194			—			19,003
Total revenues		—			—			315,808			46,734			—			362,542
Costs and expenses:
Cost of natural gas and NGLs		—			—			36,328			—			—			36,328
Operation and maintenance		—			—			64,405			5,606			—			70,011
General and administrative		—			—			35,283			5,087			—			40,370
Depreciation and amortization		660			—			75,772			9,752			—			86,184
Transaction costs		119			—			—			—			—			119
(Gain) loss on asset sales, net		—			—			(11	)		541			—			530
Long-lived asset impairment		—			—			698			879			—			1,577
Total costs and expenses		779			—			212,475			21,865			—			235,119
Other income		214			—			—			—			—			214
Interest expense		—			(51,883	)		—			—			—			(51,883	)
Early extinguishment of debt		—			(22,020	)		—			—			—			(22,020	)
Deferred Purchase Price Obligation		54,674			—			—			—			—			54,674
Income (loss) before income taxes and loss from equity method investees		54,109			(73,903	)		103,333			24,869			—			108,408
Income tax expense		(417	)		—			—			—			—			(417	)
Loss from equity method investees		—			—			—			(3,691	)		—			(3,691	)
Equity in earnings of consolidated subsidiaries		50,608			124,511			—			—			(175,119	)		—
Net income	$	104,300		$	50,608		$	103,333		$	21,178		$	(175,119	)	$	104,300

Condensed Consolidating Statements of Cash Flows. Statements of cash flows for the nine months ended September 30, 2018 and 2017 follow.

	Nine months ended September 30, 2018
	SMLP			Co-Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating adjustments			Total
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	3,687		$	(38,590	)	$	148,237		$	53,158		$	—		$	166,492

Cash flows from investing activities:
Capital expenditures		(2,101	)		—			(127,362	)		(7,570	)		—			(137,033	)
Proceeds from asset sales		—			—			—			496			—			496
Other, net		(209	)		—			—			—			—			(209	)
Advances to affiliates		—			(84,148	)		(20,802	)		(46,090	)		151,040			—
Net cash used in investing activities		(2,310	)		(84,148	)		(148,164	)		(53,164	)		151,040			(136,746	)

Cash flows from financing activities:
Distributions to common unitholders		(135,484	)		—			—			—			—			(135,484	)
Distributions to Series A Preferred unitholders		(14,250	)		—			—			—			—			(14,250	)
Borrowings under Revolving Credit Facility		—			202,000			—			—			—			202,000
Repayments under Revolving Credit Facility		—			(79,000	)		—			—			—			(79,000	)
Debt issuance costs		—			(334	)		—			—			—			(334	)
Other, net		(2,780	)		—			(881	)		(77	)		—			(3,738	)
Advances from affiliates		151,040			—			—			—			(151,040	)		—
Net cash (used in) provided by financing activities		(1,474	)		122,666			(881	)		(77	)		(151,040	)		(30,806	)
Net change in cash and cash equivalents		(97	)		(72	)		(808	)		(83	)		—			(1,060	)
Cash and cash equivalents, beginning of period		126			75			1,138			91			—			1,430
Cash and cash equivalents, end of period	$	29		$	3		$	330		$	8		$	—		$	370

	Nine months ended September 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	$	5,707		$	(45,854	)	$	176,442		$	60,202		$	—		$	196,497

Cash flows from investing activities:
Capital expenditures		(995	)		—			(64,413	)		(20,798	)		—			(86,206	)
Proceeds from asset sales		—			—			—			2,300			—			2,300
Contributions to equity method investees		—			—			—			(21,581	)		—			(21,581	)
Other, net		(579	)		—			—			—			—			(579	)
Advances to affiliates		11,768			21,658			(116,254	)		(8,441	)		91,269			—
Net cash provided by (used in) investing activities		10,194			21,658			(180,667	)		(48,520	)		91,269			(106,066	)

Cash flows from financing activities:
Distributions to unitholders		(134,066	)		—			—			—			—			(134,066	)
Borrowings under Revolving Credit Facility		—			177,500			—			—			—			177,500
Repayments under Revolving Credit Facility		—			(319,500	)		—			—			—			(319,500	)
Debt issuance costs		—			(15,891	)		—			—			—			(15,891	)
Payment of redemption and call premiums on senior notes		—			(17,913	)		—			—			—			(17,913	)
Proceeds from ATM Program issuances, net of costs		17,251			—			—			—			—			17,251
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		(2,794	)		—			—			—			—			(2,794	)
Advances from affiliates		103,037			—			—			(11,768	)		(91,269	)		—
Net cash (used in) provided by financing activities		(16,107	)		24,196			—			(11,768	)		(91,269	)		(94,948	)
Net change in cash and cash equivalents		(206	)		—			(4,225	)		(86	)		—			(4,517	)
Cash and cash equivalents, beginning of period		698			51			5,768			911			—			7,428
Cash and cash equivalents, end of period	$	492		$	51		$	1,543		$	825		$	—		$	2,911

19. SUBSEQUENT EVENTS

We have evaluated subsequent events for recognition or disclosure in the unaudited condensed consolidated financial statements and no events have occurred that require disclosure, except for the following:

In October 2018, we received information from customers on our Utica Shale, Ohio Gathering and Williston Basin segments. The impact of this new information would result in a decrease to the calculation of the undiscounted value of the Deferred Purchase Price Obligation of approximately $16.9 million, from $470.9 million to $454.0 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, 2017. 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 2017 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:

•

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;

•

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

•

In July 2018, we executed an agreement with XTO Energy Inc. (“XTO”), a wholly owned subsidiary of Exxon Mobil Corporation (“ExxonMobil”). XTO has committed to firm transportation capacity on SMLP’s Double E Pipeline project (“Double E”) under a 10-year take-or-pay agreement which increases to 500,000 dekatherms per day. Pursuant to the agreement, Summit would operate the pipeline, which is scheduled to begin operation in 2021, pending the completion of definitive agreements, final investment decision by the Summit Board of Directors, and regulatory approvals. We also executed an equity option agreement with ExxonMobil, which provides ExxonMobil or an affiliate the right to become an equity partner in Double E.

For additional information on our organization and systems, see Notes 1 and 4 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/or NGLs purchased under percent-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain DFW Midstream customers and (iv) the sale of condensate we retain from our gathering services at Grand River. These additional activities, including marketing transactions comprised of simultaneous buy and sell arrangements, expose us to direct commodity price risk and accounted for approximately 25% of total revenues during the nine months ended September 30, 2018. These additional activities, excluding marketing transactions comprised of simultaneous buy and sell arrangements, accounted for approximately 11% of total revenues during the nine months ended September 30, 2018. We expect our natural gas and crude oil marketing services to increase in future periods.

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, if any, ensure that we will recognize a minimum amount of revenue.

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the "Segment Overview for the Three and Nine Months Ended September 30, 2018 and 2017" section herein.

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
	(In thousands)
Net income	$	57,455	$	93,637		$	3,697	$	104,300
Reportable segment adjusted EBITDA
Utica Shale	$	6,521	$	8,412		$	24,459	$	25,857
Ohio Gathering		10,171		10,522			29,583		29,201
Williston Basin		19,849		16,212			54,849		51,176
Piceance/DJ Basins		29,831		30,008			86,739		86,256
Barnett Shale		10,818		10,838			31,770		35,924
Marcellus Shale		5,550		6,682			18,769		17,775

Net cash provided by operating activities	$	56,443	$	75,156		$	166,492	$	196,497
Capital expenditures (1)		46,639		40,294			137,033		86,206
Contributions to equity method investees		—		5,932			—		21,581

Distributions to common unitholders	$	45,215	$	45,037		$	135,484	$	134,066
Distributions to Series A Preferred unitholders		—		—			14,250		—
Issuance of senior notes		—		—			—		500,000
Tender and redemption of senior notes		—		—			—		(300,000	)
Net borrowings (repayments) under Revolving Credit Facility		28,000		15,000			123,000		(142,000	)
Proceeds from ATM Program common unit issuances, net of costs		—		(8	)		—		17,251

(1) See "Liquidity and Capital Resources" herein and Note 4 to the unaudited condensed consolidated financial statements for additional information on capital expenditures.

Three and nine months ended September 30, 2018. The following items are reflected in our financial results:

•

During the three and nine months ended September 30, 2018, we recognized $6.4 million and $14.8 million in gathering services and related fees from MVC shortfall adjustments. Under Topic 606, we recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.

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

•

During the third quarter of 2017, we updated the Deferred Purchase Price Obligation based on management’s estimate of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets. The revision in these estimates resulted in a decrease in the estimated undiscounted future payment obligation of $136.8 million relative to the estimates as of June 30, 2017. These changes in estimates had a favorable impact on our unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017. The decrease was primarily attributable to lower expected Business Adjusted EBITDA in 2018 and 2019 associated with the 2016 Drop Down Assets partially offset by lower estimated capital expenditures.

•

During the third quarter of 2017, we recognized $19.1 million of gathering services and related fees revenue due to a settlement of shortfall volumes with a certain Piceance/DJ Basins customer who acquired another customer’s Piceance Basin assets. In conjunction with the assignment of the related gathering agreements, the annual MVC shortfall volume measurement and settlement was amended from annually to monthly, effective July 1, 2017. We include the effect of adjustments related to MVC shortfall payments in our definition

of segment adjusted EBITDA. As such, the Piceance/DJ Basins segment adjusted EBITDA was not impacted because the revenue recognition was offset by the associated adjustments related to MVC shortfall payments for this customer.

•

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.

•

In February 2017, we completed a public offering of $500.0 million principal 5.75% Senior Notes. Concurrent with and following the offering, we initiated a tender offer for the outstanding 7.5% Senior Notes. All 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.

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;

•

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 2017 Annual Report.

How We Evaluate Our Operations

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

•

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 Polar and Divide, Tioga Midstream and Bison 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. Capital expenditures attributable to the ongoing development of Summit Permian is included in Corporate and Other. 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 4 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 nine months ended September 30, 2018.

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 2017 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.

Results of Operations

Consolidated Overview for the Three and Nine Months Ended September 30, 2018 and 2017

The following table presents certain consolidated and operating data.

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands)
Revenues:
Gathering services and related fees	$	86,427		$	96,070		$	260,373		$	298,884
Natural gas, NGLs and condensate sales		34,017			22,940			92,025			44,655
Other revenues		7,035			5,935			20,584			19,003
Total revenues		127,479			124,945			372,982			362,542
Costs and expenses:
Cost of natural gas and NGLs		26,879			18,177			71,549			36,328
Operation and maintenance		24,382			22,303			73,452			70,011
General and administrative		11,740			13,289			39,666			40,370
Depreciation and amortization		26,743			28,927			80,204			86,184
Transaction costs		—			—			—			119
Loss (gain) on asset sales, net		6			460			(6	)		530
Long-lived asset impairment		1,540			1,290			2,127			1,577
Total costs and expenses		91,290			84,446			266,992			235,119
Other income		58			79			78			214
Interest expense		(14,862	)		(17,614	)		(44,821	)		(51,883	)
Early extinguishment of debt		—			—			—			(22,020	)
Deferred Purchase Price Obligation		37,204			70,499			(53,759	)		54,674
Income before income taxes and (loss) income from equity method investees		58,589			93,463			7,488			108,408
Income tax benefit (expense)		35			(176	)		(88	)		(417	)
(Loss) income from equity method investees		(1,169	)		350			(3,703	)		(3,691	)
Net income	$	57,455		$	93,637		$	3,697		$	104,300

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,629			1,826			1,720			1,744
Aggregate average daily throughput - liquids (Mbbl/d)		96.9			74.0			90.9			74.7

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

Volumes – Gas. Natural gas throughput volumes decreased 197 MMcf/d compared to the three months ended September 30, 2017, primarily reflecting:

•

a volume throughput decrease of 104 MMcf/d for the Marcellus Shale segment.

•

a volume throughput decrease of 46 MMcf/d for the Utica Shale segment.

•

a volume throughput decrease of 23 MMcf/d for the Piceance/DJ Basins segment.

•

a volume throughput decrease of 22 MMcf/d for the Barnett Shale segment.

Natural gas throughput volumes decreased 24 MMcf/d compared to the nine months ended September 30, 2017, primarily reflecting:

•

a volume throughput decrease of 27 MMcf/d for the Piceance/DJ Basins segment.

•

a volume throughput decrease of 17 MMcf/d for the Barnett Shale segment.

•

a volume throughput increase of 12 MMcf/d for the Utica Shale segment.

•

a volume throughput increase of 9 MMcf/d for the Marcellus Shale segment.

Volumes – Liquids. Crude oil and produced water throughput volumes in the Williston Basin segment increased 22.9 Mbbl/d and 16.2 Mbbl/d compared to the three months and nine months ended September 30, 2017, primarily reflecting well completion activity behind our Polar and Divide system in the second half of 2017 and in 2018 as well as the addition of new customers.

For additional information on volumes, see the "Segment Overview for the Three and Nine Months Ended September 30, 2018 and 2017" section herein.

Revenues. Total revenues increased $2.5 million compared to the three months ended September 30, 2017 primarily reflecting:

•

an $11.1 million increase in natural gas, NGLs and condensate sales primarily attributable to increased natural gas and/or crude oil marketing activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

•

a $6.4 million increase from the recognition of MVC shortfall adjustments under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

•

a $12.3 million decrease in gathering services and related fees in the Piceance/DJ Basins as a result of an amendment in July 2017 to MVC shortfall volume measurement and settlement timing from annually to monthly.

•

a $3.4 million decrease in gathering services and related fees for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements currently recognized in cost of natural gas and NGLs under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

Total revenues increased $10.4 million compared to the nine months ended September 30, 2017 primarily reflecting:

•

a $47.4 million increase in natural gas, NGLs and condensate sales primarily attributable to increased natural gas and/or crude oil marketing activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

•

a $14.8 million increase from the recognition of MVC shortfall adjustments under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

•

a $9.9 million decrease in gathering services and related fees for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements currently recognized in cost of natural gas and NGLs under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

•

a $3.6 million decrease in gathering services and related fees for the Barnett Shale segment largely as a result of the expiration of an MVC during 2017.

•

the 2017 recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

Gathering Services and Related Fees. Gathering services and related fees decreased $9.6 million compared to the three months ended September 30, 2017, primarily reflecting:

•

a $6.4 million increase from the recognition of MVC shortfall adjustments under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

Gathering services and related fees decreased $38.5 million compared to the nine months ended September 30, 2017, primarily reflecting:

•

the 2017 recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer.

•

a $3.6 million decrease in gathering services and related fees for the Barnett Shale segment largely as a result of the expiration of an MVC during 2017.

•

a $14.8 million increase from the recognition of MVC shortfall adjustments under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales increased $11.1 million and $47.4 million compared to the three and nine months ended September 30, 2017, primarily reflecting the addition of natural gas and/or crude oil marketing services provided for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

Costs and Expenses. Total costs and expenses increased $6.8 million, compared to the three months ended September 30, 2017 primarily reflecting:

•

a $12.0 million increase in natural gas, NGLs and condensate purchases driven by increased natural gas and/or crude oil marketing activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

•

a $2.1 million increase in operation and maintenance expense primarily due to compressor overhaul maintenance.

•

a $3.4 million decrease in the cost of natural gas and NGLs for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements under Topic 606 that were previously recognized in gathering services and related fees.

•

a $2.2 million decrease in depreciation and amortization primarily due to the impairment of certain intangible and long-lived assets relating to the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017.

Total costs and expenses increased $31.9 million, compared to the nine months ended September 30, 2017 primarily reflecting:

•

a $45.0 million increase in natural gas, NGLs and condensate purchases primarily driven by increased natural gas and/or crude oil marketing activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

•

a $3.4 million increase in operation and maintenance expense primarily due to compressor overhaul maintenance.

•

a $9.9 million decrease in the cost of natural gas and NGLs for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements under Topic 606 that were previously recognized in gathering services and related fees.

•

a $6.0 million decrease in depreciation and amortization primarily due to the impairment of certain intangible and long-lived assets relating to the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $8.7 million compared to the three months ended September 30, 2017 primarily reflecting:

•

a $12.0 million increase in natural gas, NGLs, crude oil and condensate purchases driven by increased natural gas and/or crude oil marketing activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

•

the reclassification of $3.4 million in cost of natural gas and NGLs for the Williston Basin segment under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees, which is presented net in cost of natural gas and NGLs under Topic 606.

Cost of natural gas and NGLs increased $35.2 million compared to the nine months ended September 30, 2017 primarily reflecting:

•

a $45.0 million increase in natural gas, NGLs, crude oil and condensate purchases driven by increased natural gas and/or crude oil marketing activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

•

the reclassification of $9.9 million in cost of natural gas and NGLs for the Williston Basin segment under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees, which is presented net in cost of natural gas and NGLs under Topic 606.

Operation and Maintenance. Operation and maintenance expense increased $2.1 million and $3.4 million compared to the three and nine months ended September 30, 2017 primarily due to planned compressor overhaul maintenance in 2018.

General and Administrative. General and administrative expense decreased $1.5 million and $0.7 million compared to the three and nine months ended September 30, 2017. The decrease in general and administrative expense compared to the three months ended September 30, 2017 was primarily due to a $0.7 million reimbursement of previously expensed professional fees.

Depreciation and Amortization. Depreciation and amortization expense decreased $2.2 million and $6.0 million compared to the three and nine months ended September 30, 2017 due to the impairment of certain intangible and long-lived assets on the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017.

Interest Expense. Interest expense decreased $2.8 million and $7.1 million compared to the three and nine months ended September 30, 2017 as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) a lower outstanding balance on the Revolving Credit Facility and (iii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility.

Early Extinguishment of Debt. The early extinguishment of debt recognized during the nine months ended September 30, 2017 was due to the tender and redemption of the $300.0 million principal 7.5% Senior Notes.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the three and nine months ended September 30, 2018 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Notes 17 to the unaudited condensed consolidated financial statements).

For additional information, see the "Segment Overview for the Three and Nine Months Ended September 30, 2018 and 2017" and "Corporate and Other Overview for the Three and Nine Months Ended September 30, 2018 and 2017" sections herein.

Segment Overview for the Three and Nine Months Ended September 30, 2018 and 2017

Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.

	Utica Shale
	Three months ended September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
Average daily throughput (MMcf/d)		357		403	(11%)		376		364	3%

Volume throughput declined compared to the three months ended September 30, 2017 due to temporary production curtailments upstream of our Summit Utica system partially offset by the completion of new wells during 2017 and in 2018.

Volume throughput increased compared to the nine months ended September 30, 2017 due to the ongoing development of the Summit Utica system and completion of new wells during 2017 and in 2018. In addition, the TPL-7 connector project was commissioned in the second quarter of 2017 which has contributed to increased volumes. The increase was partially offset by temporary production curtailments upstream of our Summit Utica system during 2018.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended September 30,						Nine months ended September 30,
	2018			2017		Percentage Change	2018			2017		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,974		$	9,727	(18%)	$	28,437		$	28,979	(2%)
Total revenues		7,974			9,727	(18%)		28,437			28,979	(2%)
Costs and expenses:
Operation and maintenance		1,363			1,231	11%		3,672			2,836	29%
General and administrative		85			84	1%		292			286	2%
Depreciation and amortization		1,887			1,818	4%		5,773			5,213	11%
Loss on asset sales, net		5			542	(99%)		5			542	(99%)
Long-lived asset impairment		1,265			594	113%		1,265			878	44%
Total costs and expenses	��	4,605			4,269	8%		11,007			9,755	13%
Add:
Depreciation and amortization		1,887			1,818			5,773			5,213
Adjustments related to capital reimbursement activity		(5	)		—			(14	)		—
Loss on asset sales, net		5			542			5			542
Long-lived asset impairment		1,265			594			1,265			878
Segment adjusted EBITDA	$	6,521		$	8,412	(22%)	$	24,459		$	25,857	(5%)

Three months ended September 30, 2018. Segment adjusted EBITDA decreased $1.9 million compared to the three months ended September 30, 2017 primarily reflecting:

•

a $1.8 million decrease in gathering services and related fees from a lower margin rate mix along with a decrease in volume throughput due to temporary production curtailments. The decrease was partially offset by an increase in volume throughput associated with new wells completed in 2017 and 2018.

Nine months ended September 30, 2018. Segment adjusted EBITDA decreased $1.4 million compared to the nine months ended September 30, 2017 primarily reflecting:

•

a $0.5 million decrease in gathering services and related fees from a lower margin rate mix associated with the TPL-7 connector project commissioned in the second quarter of 2017 along with a decrease in volume throughput due to temporary production curtailments. The decrease was partially offset by an increase in volume throughput associated with new wells completed in 2017 and 2018.

•

a $0.8 million increase in operation and maintenance expense primarily related to increases in various general operating expenses.

Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. We recognize our proportionate share of earnings or loss in net income on a one-month lag based on the financial information available to us during the reporting period.

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

	Ohio Gathering
	Three months ended September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
Average daily throughput (MMcf/d)		797		763	4%		765		746	3%

Volume throughput for the Ohio Gathering increased compared to the three and nine months ended September 30, 2017 primarily as a result of increased drilling activity during the second half of 2017 and in 2018 offset by natural production declines on existing wells on the system.

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

	Ohio Gathering
	Three months ended September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	10,171	$	10,522	(3%)	$	29,583	$	29,201	1%
Segment adjusted EBITDA	$	10,171	$	10,522	(3%)	$	29,583	$	29,201	1%

Segment adjusted EBITDA for equity method investees decreased $0.4 million compared to the three months ended September 30, 2017 primarily as a result of an increase in repairs and maintenance expense.

Segment adjusted EBITDA for equity method investees increased $0.4 million compared to the nine months ended September 30, 2017 primarily as a result of improved results at OCC and the increased volumes associated with the installation of additional compression in the dry gas window beginning in March 2017.

Williston Basin. The Polar and Divide, Tioga Midstream and Bison Midstream systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)		19		21	(10%)		18		19	(5%)

Aggregate average daily throughput - liquids (Mbbl/d)		96.9		74.0	31%		90.9		74.7	22%

Natural gas. Natural gas volume throughput decreased compared to the three and nine months ended September 30, 2017 primarily due to natural production declines.

Liquids. The increase in liquids volume throughput compared to the three and nine months ended September 30, 2017 primarily reflected well completion activity on our Polar and Divide system in the second half of 2017 and in 2018 as well as the addition of new customers.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended September 30,							Nine months ended September 30,
	2018			2017			Percentage Change	2018			2017			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	18,020		$	17,473		3%	$	58,792		$	95,179		(38%)
Natural gas, NGLs and condensate sales		7,953			7,849		1%		23,149			20,655		12%
Other revenues		3,037			2,499		22%		8,909			7,986		12%
Total revenues		29,010			27,821		4%		90,850			123,820		(27%)
Costs and expenses:
Cost of natural gas and NGLs		4,605			7,474		(38%)		13,413			20,686		(35%)
Operation and maintenance		5,920			5,670		4%		18,630			18,472		1%
General and administrative		318			447		(29%)		1,682			1,739		(3%)
Depreciation and amortization		5,672			8,405		(33%)		16,903			25,171		(33%)
Loss (gain) on asset sales, net		1			(82	)	*		63			(23	)	*
Long-lived asset impairment		—			—		*		—			3		*
Total costs and expenses		16,516			21,914		(25%)		50,691			66,048		(23%)
Add:
Depreciation and amortization		5,672			8,405				16,903			25,171
Adjustments related to MVC shortfall payments		2,032			1,982				(1,354	)		(31,747	)
Adjustments related to capital reimbursement activity		(350	)		—				(922	)		—
Loss (gain) on asset sales, net		1			(82	)			63			(23	)
Long-lived asset impairment		—			—				—			3
Segment adjusted EBITDA	$	19,849		$	16,212		22%	$	54,849		$	51,176		7%

* Not considered meaningful

Three months ended September 30, 2018. Segment adjusted EBITDA increased $3.6 million compared to the three months ended September 30, 2017 primarily reflecting an increase in volume throughput on our Polar and Divide system.

Other items to note:

•

The decrease in the cost of natural gas and NGLs includes a $3.4 million reduction in expense due to the reclassification of amounts under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

Nine months ended September 30, 2018. Segment adjusted EBITDA increased $3.7 million compared to the nine months ended September 30, 2017 primarily reflecting an increase in volume throughput on our Polar and Divide system. The nine months ended September 30, 2017 includes the recognition of $2.6 million of business interruption recoveries in the first quarter of 2017 and the recognition of $2.3 million in gathering services fees relating to previously billed but unearned revenue.

Other items to note:

•

The decrease in the cost of natural gas and NGLs includes a $9.9 million reduction in expense due to the reclassification of amounts under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees under Topic 606 (see Note 3 in the unaudited condensed consolidated financial statements).

Piceance/DJ Basins. The Grand River and Niobrara G&P systems provide midstream services for the Piceance/DJ Basins reportable segment. Volume throughput for our Piceance/DJ Basins reportable segment follows.

	Piceance/DJ Basins
	Three months ended September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
Aggregate average daily throughput (MMcf/d)		571		594	(4%)		574		601	(4%)

Volume throughput decreased compared to the three and nine months ended September 30, 2017 as a result of the continued suspended drilling activities by one of Grand River’s key customers partially offset by the ongoing drilling and completion activity across our gathering footprint during the second half of 2017 and in 2018.

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

	Piceance/DJ Basins
	Three months ended September 30,							Nine months ended September 30,
	2018			2017			Percentage Change	2018			2017			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	36,743		$	48,744		(25%)	$	108,207		$	107,385		1%
Natural gas, NGLs and condensate sales		3,650			3,258		12%		12,650			9,829		29%
Other revenues		2,072			1,873		11%		6,187			5,232		18%
Total revenues		42,465			53,875		(21%)		127,044			122,446		4%
Costs and expenses:
Cost of natural gas and NGLs		2,286			2,139		7%		7,814			6,249		25%
Operation and maintenance		10,284			8,488		21%		30,772			26,566		16%
General and administrative		27			1,040		(97%)		1,692			2,264		(25%)
Depreciation and amortization		12,512			12,199		3%		37,517			36,635		2%
Loss on asset sales, net		—			—		*		—			3		*
Long-lived asset impairment		276			696		*		276			696		*
Total costs and expenses		25,385			24,562		3%		78,071			72,413		8%
Add:
Depreciation and amortization		12,512			12,199				37,517			36,635
Adjustments related to MVC shortfall payments		—			(12,200	)			(93	)		(1,111	)
Adjustments related to capital reimbursement activity		(37	)		—				66			—
Loss on asset sales, net		—			—				—			3
Long-lived asset impairment		276			696				276			696
Segment adjusted EBITDA	$	29,831		$	30,008		(1%)	$	86,739		$	86,256		1%

* Not considered meaningful

Three months ended September 30, 2018. Segment adjusted EBITDA decreased $0.2 million compared to the three months ended September 30, 2017, primarily reflecting:

•

an increase, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees primarily as a result of the continued suspended drilling activities by one of Grand River’s key customers partially offset by the ongoing drilling and completion activity across our gathering footprint during the second half of 2017 and in 2018.

•

a $1.8 million increase in operation and maintenance expense primarily due to compressor overhaul costs during the period.

•

a $1.0 million decrease in general and administrative expense primarily due to a reimbursement of previously expensed professional fees.

Nine months ended September 30, 2018. Segment adjusted EBITDA increased $0.5 million compared to the nine months ended September 30, 2017, primarily reflecting:

•

a $4.2 million increase in operation and maintenance expense primarily due to compressor overhaul costs during the period.

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

	Barnett Shale
	Three months ended September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
Average daily throughput (MMcf/d)		232		254	(9%)		253		270	(6%)

Volume throughput declined compared to the three and nine months ended September 30, 2017 reflecting natural production declines partially offset by new volumes from completion activity during the fourth quarter of 2017 and first quarter of 2018.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended September 30,						Nine months ended September 30,
	2018			2017		Percentage Change	2018			2017			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	18,318		$	14,154	29%	$	46,035		$	47,235		(3%)
Natural gas, NGLs and condensate sales		789			625	26%		1,715			1,956		(12%)
Other revenues (1)		1,913			1,915	—%		5,595			6,149		(9%)
Total revenues		21,020			16,694	26%		53,345			55,340		(4%)
Costs and expenses:
Operation and maintenance		5,111			5,554	(8%)		16,226			17,805		(9%)
General and administrative		238			246	(3%)		784			831		(6%)
Depreciation and amortization		3,911			3,885	—%		11,728			11,711		—%
(Gain) loss on asset sales, net		—			—	*		(74	)		8		*
Total costs and expenses		9,260			9,685	(4%)		28,664			30,355		(6%)
Add:
Depreciation and amortization		3,760			3,735			11,276			11,259
Adjustments related to MVC shortfall payments		(5,031	)		94			(5,094	)		(328	)
Adjustments related to capital reimbursement activity		329			—			981			—
(Gain) loss on asset sales, net		—			—			(74	)		8
Segment adjusted EBITDA	$	10,818		$	10,838	—%	$	31,770		$	35,924		(12%)

*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 September 30, 2018. Segment adjusted EBITDA was slightly down compared to the three months ended September 30, 2017.

Nine months ended September 30, 2018. Segment adjusted EBITDA decreased $4.2 million compared to the nine months ended September 30, 2017 primarily reflecting:

•

a $6.0 million decrease, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees associated with the expiration of an MVC during 2017 of $3.0 million in addition to lower volume throughput.

•

a $1.6 million decrease in operation and maintenance expense primarily from lower electricity expense associated with lower volume throughput.

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 September 30,					Nine months ended September 30,
	2018		2017		Percentage Change	2018		2017		Percentage Change
Average daily throughput (MMcf/d)		450		554	(19%)		499		490	2%

Volume throughput decreased compared to the three months ended September 30, 2017 primarily due to natural production declines partially offset by the completion, in the second half of 2017 and first quarter of 2018, of drilled but uncompleted (“DUC”) wells behind the Mountaineer Midstream system that had been deferred since the third quarter of 2015.

Volume throughput increased compared to the nine months ended September 30, 2017 primarily due to the completion, in the second half of 2017 and first quarter of 2018, of DUC wells behind the Mountaineer Midstream system that had been deferred since the third quarter of 2015.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended September 30,						Nine months ended September 30,
	2018			2017		Percentage Change	2018			2017		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,150		$	8,160	(12%)	$	23,025		$	22,429	3%
Total revenues		7,150			8,160	(12%)		23,025			22,429	3%
Costs and expenses:
Operation and maintenance		1,458			1,358	7%		3,884			4,334	(10%)
General and administrative		98			120	(18%)		309			320	(3%)
Depreciation and amortization		2,273			2,268	—%		6,819			6,794	—%
Total costs and expenses		3,829			3,746	2%		11,012			11,448	(4%)
Add:
Depreciation and amortization		2,273			2,268			6,819			6,794
Adjustments related to capital reimbursement activity		(44	)		—			(63	)		—
Segment adjusted EBITDA	$	5,550		$	6,682	(17%)	$	18,769		$	17,775	6%

Three months ended September 30, 2018. Segment adjusted EBITDA decreased $1.1 million compared to the three months ended September 30, 2017 primarily reflecting a $1.0 million decrease in gathering services and related fees as a result of lower volumes due to natural declines partially offset by increased drilling and completion activity.

Nine months ended September 30, 2018. Segment adjusted EBITDA increased $1.0 million compared to the nine months ended September 30, 2017 primarily reflecting:

•

a $0.6 million increase in gathering services and related fees as a result of slightly higher volumes generated by increased drilling and completion activity.

•

a $0.5 million decrease in operation and maintenance expense primarily due to lower property taxes during the period.

Corporate and Other Overview for the Three and Nine Months Ended September 30, 2018 and 2017

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.

	Corporate and Other
	Three months ended September 30,							Nine months ended September 30,
	2018			2017			Percentage Change	2018		2017			Percentage Change
	(Dollars in thousands)
Revenues:
Total revenues		19,860			8,667		*		50,281		9,527		*
Costs and expenses:
Cost of natural gas and NGLs		19,988			8,564		*		50,322		9,393		*
General and administrative		10,974			11,352		(3%)		34,907		34,930		—%
Interest expense		14,862			17,614		(16%)		44,821		51,883		(14%)
Early extinguishment of debt (1)		—			—		*		—		22,020		*
Deferred Purchase Price Obligation		(37,204	)		(70,499	)	*		53,759		(54,674	)	*

* Not considered meaningful

(1) 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.

Total Revenues. Total revenues attributable to Corporate and Other was due to the growth of natural gas and crude oil marketing services activity for the Piceance/DJ Basins, Barnett Shale and Williston Basin segments.

General and Administrative. General and administrative expense decreased $0.4 million compared to the three months ended September 30, 2017 and was flat compared to the nine months ended September 30, 2017.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the three and nine months ended September 30, 2018 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 17 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

We had no capital markets activity during the nine months ended September 30, 2018. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2017 Annual Report.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. As of September 30, 2018, the outstanding balance of the Revolving Credit Facility was $384.0 million and the unused portion totaled $866.0 million. There were no defaults or events of default during the nine months ended September 30, 2018, and, as of September 30, 2018, we were in compliance with the covenants in the Revolving Credit Facility.

Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the nine months ended September 30, 2018 on either series of senior notes.

For additional information on our long-term debt, see Notes 10 and 18 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 17 to the unaudited condensed consolidated financial statements).

Cash Flows

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

	Nine months ended September 30,
	2018			2017
	(In thousands)
Net cash provided by operating activities	$	166,492		$	196,497
Net cash used in investing activities		(136,746	)		(106,066	)
Net cash used in financing activities		(30,806	)		(94,948	)
Net change in cash and cash equivalents	$	(1,060	)	$	(4,517	)

Operating activities. Cash flows from operating activities for the nine months ended September 30, 2018 primarily reflected (i) a $34.1 million decrease in customer payments from minimum volume commitments; (ii) a $3.3 million decrease in cash interest payments due to the extinguishment of the 7.5% Senior Notes in the first quarter of 2017; and (iii) other changes in working capital.

Investing activities. Cash flows used in investing activities during the nine months ended September 30, 2018 primarily reflected:

•

$137.0 million of capital expenditures attributable to the ongoing development of Summit Permian of $66.9 million, the Piceance/DJ Basins of $44.2 million, the Williston Basin of $18.5 million and Summit Utica of $3.9 million.

Cash flows used in investing activities during the nine months ended September 30, 2017 primarily reflected:

•

$86.2 million of capital expenditures primarily attributable to the ongoing development of the Summit Permian system as well as the continued development in the Piceance/DJ Basins and Williston Basin segments; and

•

$21.6 million of capital contributions to Ohio Gathering.

Financing activities. Cash flows used in financing activities during the nine months ended September 30, 2018 primarily reflected:

•

$149.7 million of distributions; and

•

$123.0 million of net borrowings under our Revolving Credit Facility.

Cash flows used in financing activities during the nine months ended September 30, 2017 primarily reflected:

•

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

•

$142.0 million of net repayments under our Revolving Credit Facility;

•

$134.1 million of distributions;

•

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

•

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

Contractual Obligations Update

In March 2016, we recognized a liability of $507.4 million for the Deferred Purchase Price Obligation 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 $470.9 million based on information available as of September 30, 2018. There are no cash interest payments associated with the Deferred Purchase Price Obligation. For additional information, see Note 17 to the unaudited condensed consolidated financial statements.

Capital Requirements

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

•

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

•

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

For the nine months ended September 30, 2018, cash paid for capital expenditures totaled $137.0 million (see Note 4 to the unaudited condensed consolidated financial statements) which included $13.5 million of maintenance capital expenditures. For the nine months ended September 30, 2018, there were no contributions to equity method investees (see Note 8 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 our 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 12 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 4, 9 and 11 to the unaudited condensed consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the nine months ended September 30, 2018.

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, 2017 except for the adoption of Topic 606 (see Notes 2 and 3).

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 during the nine months ended September 30, 2018.

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, our subsidiaries, 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;

•

the ability to attract and retain key management personnel;

•

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

•

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

•

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

•

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

•

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

•

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

•

weather conditions and 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, preferred units and senior notes.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our debt portfolio. As of September 30, 2018, we had $800.0 million principal of fixed-rate Senior Notes and $384.0 million outstanding under our variable rate Revolving Credit Facility (see Note 10 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, 2017. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2017 Annual Report.

Commodity Price Risk

We currently generate a substantial majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, certain 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, 2017. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2017 Annual Report.

Item 4. Controls and Procedures.

Under the direction of our General Partner's Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of September 30, 2018 and (ii) no change in internal control over financial reporting occurred during the quarter ended September 30, 2018, 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 16 to our unaudited condensed consolidated financial statements “Commitments and Contingencies” and in the 2017 Annual Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of (i) the 2017 Annual Report and (ii) the quarterly report on Form 10-Q for the quarterly period ended March 31, 2018 as filed with the SEC on May 4, 2018 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		Second Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of November 14, 2017 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated November 14, 2017 (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 filed October 4, 2012 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Executive Vice President and Chief Financial Officer
32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, and Matthew S. Harrison, Executive Vice President and Chief Financial Officer
101.INS	**	XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	**	XBRL Taxonomy Extension Schema
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	XBRL Taxonomy Extension Label Linkbase
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase

** 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.

SIGNATURES

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

	Summit Midstream Partners, LP

	(Registrant)

	By: Summit Midstream GP, LLC (its General Partner)

November 9, 2018	/s/ Matthew S. Harrison

	Matthew S. Harrison, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Summit Midstream Partners (SMLP) 10-Q2018 Q3 Quarterly report

Content analysis