Summit Midstream Partners, LP - Quarter Report: 2020 September (Form 10-Q)

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, 2020

☐	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.)

910 Louisiana Street, Suite 4200

Houston, TX

(Address of principal executive offices)

77002

(Zip Code)

(832) 413-4770

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	SMLP	New York Stock Exchange

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

☐

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 30, 2020
Common Units		56,624,887 units

TABLE OF CONTENTS

COMMONLY USED OR DEFINED TERMS		2

PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets.	4
	Unaudited Condensed Consolidated Statements of Operations.	5
	Unaudited Condensed Consolidated Statements of Partners' Capital.	6
	Unaudited Condensed Consolidated Statements of Cash Flows.	8
	Notes to Unaudited Condensed Consolidated Financial Statements.	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	51
Item 4.	Controls and Procedures.	52

PART II	OTHER INFORMATION	53
Item 1.	Legal Proceedings.	53
Item 1A.	Risk Factors.	53
Item 5.	Other Information.	55
Item 6.	Exhibits.	56

SIGNATURES		57

COMMONLY USED OR DEFINED TERMS

2016 Drop Down	the Partnership's March 3, 2016 acquisition from SMP Holdings 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
2022 Senior Notes	Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
2025 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 crude oil or as a free gas cap above the crude 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, as subsequently amended, also known as the DPPO
DFW Midstream	DFW Midstream Services, LLC
DJ Basin	Denver-Julesburg Basin
Double E	Double E Pipeline, LLC
Double E Project	the development and construction of a long-haul natural gas pipeline with an initial throughput capacity of 1.35 billion cubic feet per day that will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas
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
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
GP	general partner
Grand River	Grand River Gathering, LLC
Guarantor Subsidiaries	Bison Midstream and its subsidiaries, Grand River and its subsidiaries, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, OpCo, Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer Midstream
LIBOR	London Interbank Offered Rate
Mbbl	one thousand barrels
Mbbl/d	one thousand barrels per day
Mcf	one thousand cubic feet
Meadowlark Midstream	Meadowlark Midstream Company, LLC
MMcf	one million cubic feet
MMcf/d	one million cubic feet per day
Mountaineer Midstream	Mountaineer Midstream Company, LLC
MVC	minimum volume commitment
NGLs	natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from unprocessed natural gas streams become liquid under various levels of higher pressure and lower temperature
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
Permian Holdco	Summit Permian Transmission Holdco, 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
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, the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 and the Third Amendment to Third Amended and Restated Credit Agreement dated as of December 24, 2019
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) impairments and (viii) other noncash expenses or losses, less other noncash income or gains
Senior Notes	The 2022 Senior Notes and the 2025 Senior Notes, collectively
Series A Preferred Units	Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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 Holdings	SMLP Holdings, LLC
SMLP LTIP	SMLP Long-Term Incentive Plan
SMP Holdings	Summit Midstream Partners Holdings, LLC, also known as SMPH
SMPH Term Loan	the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings, as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent
Subsidiary Series A Preferred Units	Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco
Summit Holdings	Summit Midstream Holdings, LLC
Summit Investments	Summit Midstream Partners, LLC
Summit Marketing	Summit Midstream Marketing, LLC
Summit Permian	Summit Midstream Permian, LLC
Summit Permian II	Summit Midstream Permian II, LLC
Summit Permian Transmission	Summit Permian Transmission, 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
the Partnership Agreement	the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership dated May 28, 2020
throughput volume	the volume of natural gas, crude oil or produced water gathered, 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,
	2020		2019
	(In thousands, except unit amounts)
ASSETS
Cash and cash equivalents	$	50,272	$	9,530
Restricted cash		24		27,392
Accounts receivable, net		76,497		97,418
Other current assets		4,559		5,521
Total current assets		131,352		139,861
Property, plant and equipment, net		1,840,284		1,882,489
Intangible assets, net		207,766		232,278
Investment in equity method investees		389,088		309,728
Other noncurrent assets		4,989		9,742
TOTAL ASSETS	$	2,573,479	$	2,574,098

LIABILITIES AND CAPITAL
Trade accounts payable	$	16,205	$	24,415
Accrued expenses		11,353		11,339
Deferred revenue		17,827		13,493
Ad valorem taxes payable		6,931		8,477
Accrued interest		12,092		12,346
Accrued environmental remediation		1,553		1,725
Other current liabilities		10,747		12,206
Term loan (See TL Restructuring discussion in Note 8)		155,200		5,546
Total current liabilities		231,908		89,547
Long-term debt		1,390,842		1,622,279
Noncurrent deferred revenue		41,755		38,709
Noncurrent accrued environmental remediation		2,003		2,926
Other noncurrent liabilities		4,536		7,951
Total liabilities		1,671,044		1,761,412
Commitments and contingencies (Note 14)

Mezzanine Capital
Subsidiary Series A Preferred Units (83,842 and 30,058 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)		85,800		27,450

Partners' Capital
Series A Preferred Units (237,184 and 300,000 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)		249,351		293,616
Common limited partner capital (56,624,887 and 45,318,866 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)		567,284		305,550
Noncontrolling interest		-		186,070
Total partners' capital		816,635		785,236
TOTAL LIABILITIES AND CAPITAL	$	2,573,479	$	2,574,098

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,
	2020			2019			2020			2019
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	71,964		$	80,968		$	229,667		$	243,039
Natural gas, NGLs and condensate sales		10,783			12,219			35,246			68,438
Other revenues		7,406			7,000			22,150			19,804
Total revenues		90,153			100,187			287,063			331,281
Costs and expenses:
Cost of natural gas and NGLs		8,632			7,472			22,945			50,802
Operation and maintenance		22,168			26,231			65,131			74,771
General and administrative		10,561			10,029			39,908			38,979
Depreciation and amortization		29,505			27,443			88,801			82,044
Transaction costs		726			129			1,944			2,562
Gain on asset sales, net		(104	)		(347	)		(270	)		(1,595	)
Long-lived asset impairment		—			—			4,475			45,021
Goodwill impairment		—			16,211			—			16,211
Total costs and expenses		71,488			87,168			222,934			308,795
Other income		795			12			644			304
Interest expense		(19,018	)		(23,462	)		(64,836	)		(68,547	)
Gain on early extinguishment of debt		24,690			—			78,925			—
Income (loss) before income taxes and equity method investment income (loss)		25,132			(10,431	)		78,862			(45,757	)
Income tax benefit (expense)		(298	)		(21	)		104			(1,427	)
Income (loss) from equity method investees		795			(677	)		7,146			(1,197	)
Net income (loss)	$	25,629		$	(11,129	)	$	86,112		$	(48,381	)
Less:
Net income (loss) attributable to noncontrolling interest		—			(10,340	)		(3,274	)		(37,251	)
Net income (loss) attributable to limited partners		25,629			(789	)		89,386			(11,130	)
Net income attributable to Series A Preferred Units		6,481			7,125			20,731			21,375
Net income attributable to Subsidiary Series A Preferred Units		7,298			—			9,640			—
Add:
Deemed contribution on exchange of preferred units		54,945			—			54,945			—
Net income (loss) attributable to common limited partners	$	66,795		$	(7,914	)	$	113,960		$	(32,505	)

Net income (loss) per limited partner unit:
Common unit – basic	$	1.29		$	(0.17	)	$	2.41		$	(0.72	)
Common unit – diluted	$	1.25		$	(0.17	)	$	2.34		$	(0.72	)

Weighted-average limited partner units outstanding:
Common units – basic		51,974			45,319			47,331			45,319
Common units – diluted		53,650			45,319			48,782			45,319

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


	Noncontrolling Interest						Partners' Capital
	Series A Preferred Units			Common Noncontrolling Interests ⁽¹⁾			Series A Preferred Units			Partners' Capital			Total
	(In thousands)
Partners' capital, January 1, 2020	$	293,616		$	186,070		$	—		$	305,550		$	785,236
Net income (loss)		7,125			(1,881	)		—			(2,427	)		2,817
Net cash distributions to SMLP unitholders		—			(6,037	)		—			—			(6,037	)
Unit-based compensation		—			2,723			—			—			2,723
Effect of common unit issuances under SMLP LTIP		—			2,322			—			(2,322	)		—
Tax withholdings and associated payments on vested SMLP LTIP awards		—			(984	)		—			—			(984	)
Partners' capital, March 31, 2020		300,741			182,213			—			300,801			783,755
Net income (loss)		4,750			(1,393	)		2,375			49,592			55,324
Unit-based compensation		—			1,331			—			515			1,846
Tax withholdings and associated payments on vested SMLP LTIP awards		—			(34	)		—			(28	)		(62	)
GP Buy-In Transaction assumption of noncontrolling interest in SMLP		(305,491	)		(182,117	)		305,491			182,117			—
Repurchase of common units under GP Buy-In Transaction		—			—			—			(44,078	)		(44,078	)
Other		—			—			—			(61	)		(61	)
Partners' capital, June 30, 2020		—			—			307,866			488,858			796,724
Net income (loss)		—			—			6,481			11,850			18,331
Unit-based compensation		—			—			—			1,622			1,622
Tax withholdings and associated payments on vested SMLP LTIP awards		—			—			—			(117	)		(117	)
Tax withholdings on Series A Preferred Unit Exchange		—			—			—			(237	)		(237	)
Conversion of Series A Preferred Units to SMLP common units inclusive of a $54.9 million deemed contribution to common unit holders (Note 10)		—			—			(64,996	)		64,996			—
Other		—			—			—			312			312
Partners' capital, September 30, 2020	$	-		$	-		$	249,351		$	567,284		$	816,635

⁽¹⁾ Prior to the GP Buy-In Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.

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

(continued)


	Noncontrolling Interest
	Series A Preferred Units			Common Noncontrolling Interests⁽¹⁾			Partners' Capital			Total
	(In thousands)
Partners' capital, January 1, 2019	$	293,616		$	554,472		$	543,479		$	1,391,567
Net income (loss)		7,125			(25,570	)		(21,835	)		(40,280	)
Net cash distributions to SMLP unitholders		—			(27,374	)		—			(27,374	)
Unit-based compensation		—			2,526			—			2,526
Effect of common unit issuances under SMLP LTIP		—			2,387			(2,387	)		—
Tax withholdings and associated payments on vested SMLP LTIP awards		—			(2,524	)		—			(2,524	)
Conversion of noncontrolling interest related to cancellation of subsidiary incentive distribution rights		—			(48,203	)		48,203			—
Partners' capital, March 31, 2019		300,741			455,714			567,460			1,323,915
Net income (loss)		7,125			(1,341	)		(2,756	)		3,028
Net cash distributions to SMLP unitholders		(14,250	)		(13,826	)		—			(28,076	)
Net cash distributions to Energy Capital Partners		—			—			(68,984	)		(68,984	)
Unit-based compensation		—			1,393			—			1,393
Effect of common unit issuances under SMLP LTIP		—			40			(40	)		—
Tax withholdings and associated payments on vested SMLP LTIP awards		—			(93	)		—			(93	)
Partners' capital, June 30, 2019		293,616			441,887			495,680			1,231,183
Net income (loss)		7,125			(10,340	)		(7,914	)		(11,129	)
Net cash distributions to SMLP unitholders		—			(13,829	)		—			(13,829	)
Unit-based compensation		—			1,451			—			1,451
Effect of common unit issuances under SMLP LTIP		—			173			(173	)		—
Tax withholdings and associated payments on vested SMLP LTIP awards		—			55			—			55
Partners' capital, September 30, 2019	$	300,741		$	419,397		$	487,593		$	1,207,731

⁽¹⁾ Prior to the GP Buy-In Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.

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,
	2020			2019
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	86,112		$	(48,381	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		89,505			83,030
Noncash lease expense		1,925			2,299
Amortization of debt issuance costs		4,870			4,719
Unit-based and noncash compensation		6,191			5,370
(Income) loss from equity method investees		(7,146	)		1,197
Distributions from equity method investees		19,859			28,008
Gain on asset sales, net		(270	)		(1,595	)
Gain on early extinguishment of debt		(78,925	)		—
Gain on fair value of warrants		(838	)		—
Long-lived asset impairment		4,475			45,021
Goodwill impairment		—			16,211
Changes in operating assets and liabilities:
Accounts receivable		20,922			8,363
Trade accounts payable		470			820
Accrued expenses		(1,078	)		(11,965	)
Deferred revenue, net		7,379			1,910
Ad valorem taxes payable		(1,546	)		(2,061	)
Accrued interest		2,680			3,065
Accrued environmental remediation, net		(1,368	)		(2,025	)
Other, net		(6,410	)		(6,369	)
Net cash provided by operating activities		146,807			127,617
Cash flows from investing activities:
Capital expenditures		(35,312	)		(151,663	)
Proceeds from asset sale (net of cash of $1,475 for the period ended September 30, 2019)		—			90,111
Distribution from equity method investment		—			7,252
Investment in equity method investee		(92,072	)		(11,330	)
Other, net		2,486			343
Net cash used in investing activities		(124,898	)		(65,287	)
Cash flows from financing activities:
Net cash distributions to noncontrolling interest SMLP unitholders		(6,037	)		(55,029	)
Series A Preferred Unit distributions		—			(14,250	)
Net cash distributions to Energy Capital Partners		—			(68,984	)
Borrowings under Revolving Credit Facility		165,500			265,000
Repayments on Revolving Credit Facility		(34,000	)		(131,000	)
Repayments on SMPH Term Loan		(6,300	)		(59,500	)
Open Market Repurchases of 2022 and 2025 Senior Notes (Note 8)		(82,844	)		—
Tender Offers of 2022 and 2025 Senior Notes (Note 8)		(48,712	)		—
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs		48,710			—
Borrowings under ECP Loans (Note 8)		35,000			—
Repayment of ECP Loans (Note 8)		(35,000	)		—
Purchase of common units in GP Buy-In Transaction		(41,778	)		—
Debt issuance costs		(835	)		(584	)
Proceeds from asset sale		288			—
Other, net		(2,527	)		(3,930	)
Net cash provided by (used in) financing activities		(8,535	)		(68,277	)
Net change in cash, cash equivalents and restricted cash		13,374			(5,947	)
Cash, cash equivalents and restricted cash, beginning of period		36,922			16,173
Cash, cash equivalents and restricted cash, end of period	$	50,296		$	10,226

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. SMLP is a value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in 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.

On May 28, 2020, the Partnership closed the transactions contemplated by the Purchase Agreement (the “Purchase Agreement”), dated May 3, 2020, with affiliates of its then private equity sponsor, Energy Capital Partners II, LLC (“ECP”), to acquire Summit Midstream Partners, LLC (“Summit Investments”). The purchase of Summit Investments resulted in the Partnership acquiring an indirect ownership interest in Summit Midstream Partners Holdings, LLC, a Delaware limited liability company (“SMP Holdings”), which in turn owned (a) 34,604,581 SMLP common units representing limited partner interests in the Partnership (the “common units”) that were pledged as collateral under the SMPH Term Loan, (b) 10,714,285 SMLP common units that were not pledged as collateral under the SMPH Term Loan and (c) a deferred purchase price obligation receivable owed by the Partnership. In addition, the Partnership acquired 5,915,827 SMLP common units held by an affiliate of ECP. The total purchase price was $35.0 million in cash and warrants to purchase up to 10 million SMLP common units (refer to Note 11 – Partners’ Capital and Mezzanine Capital for additional details). Pursuant to the Purchase Agreement, the Partnership, through its indirect ownership interest of SMP Holdings, will retain any liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream Company, LLC, a subsidiary of the Partnership, that occurred near Williston, North Dakota and was discovered on January 6, 2015. These transactions are collectively referred to as the “GP Buy-In Transaction.”

As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner. Following the closing of the GP Buy-In Transaction, the Partnership retired 16,630,112 SMLP common units it acquired that are not pledged as collateral under the SMPH Term Loan. The 34,604,581 SMLP common units that are pledged as collateral under the SMPH Term Loan are not considered outstanding with respect to voting and distributions under the Partnership Agreement so long as they are held by a subsidiary of the Partnership.

Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein, prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled SMLP and SMLP’s financial statements were consolidated into Summit Investments.

Business Operations. The Partnership provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. The Partnership’s results are primarily driven by the volumes of natural gas that it gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers.

Presentation and Consolidation. The condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein.

The accompanying condensed consolidated financial statements were prepared using GAAP for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. As permitted under those rules, certain information relating to the Partnership’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted. Therefore, these condensed consolidated financial statements should be read in conjunction with the

consolidated financial statements and the notes thereto included in the Partnership’s Annual Report for the year ended December 31, 2019 (“2019 Annual Report”). The Partnership believes the disclosures made are adequate to make the information presented not misleading.

Risks and Uncertainties. The Partnership is closely monitoring the impact of the outbreak of COVID-19 on all aspects of its business, including how it has impacted and will impact its customers, employees, supply chain and distribution network. While COVID-19 did not have a material adverse effect on the Partnership’s reported results for the first nine months of 2020, the Partnership is unable to predict the ultimate impact that COVID-19 may have on its business, future results of operations, financial position or cash flows.

Given the dynamic nature of the COVID-19 pandemic and related market conditions, the Partnership cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on its business. The full extent to which the Partnership’s operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

2. SUMMARY OF RECENTLY ISSUED ACCOUNTING STANDARDS APPLICABLE TO THE PARTNERSHIP

Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. The Partnership reviews new pronouncements to determine the impact, if any, on its financial statements. Accounting standards that have or could possibly have a material effect on the Partnership’s financial statements are discussed below.

Recently Adopted Accounting Pronouncements. The Partnership recently adopted the following accounting pronouncements:

•

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. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on the Partnership’s condensed consolidated financial statements or disclosures.

•

ASU No. 2016-13 Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 requires the use of a current expected loss model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU 2016-13 on January 1, 2020 did not have a material impact on the Partnership’s condensed consolidated financial statements or disclosures.

Accounting Pronouncements Not Yet Adopted. The Partnership has not yet adopted the following accounting pronouncements as of September 30, 2020:

•

ASU No. 2020-06 Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815 – 40) (“ASU 2020-06”). ASU 2020-06 simplifies the

accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The Partnership is currently evaluating the provisions of ASU 2020-06 to determine its impact on the Partnership’s condensed consolidated financial statements and disclosures.

•

ASU No. 2020-04 Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU 2020-04 are effective as of March 12, 2020 through December 31, 2022. The Partnership is currently evaluating the provisions of ASU 2020-04 to determine its impact on the Partnership’s condensed consolidated financial statements and disclosures.

3. REVENUE

Performance obligations. The following table presents estimated revenue expected to be recognized during the remainder of 2020 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.

	2020		2021		2022		2023		2024		Thereafter
	(In thousands)
Gathering services and related fees	$	29,678	$	102,127	$	84,736	$	66,693	$	50,608	$	56,912

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 16 – Segment Information.

	Three months ended September 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	8,385	$	-	$	-	$	8,385
Williston Basin		10,941		4,958		3,136		19,035
DJ Basin		6,051		17		826		6,894
Permian Basin		2,595		4,803		168		7,566
Piceance Basin		26,576		528		1,233		28,337
Barnett Shale		10,545		477		1,399		12,421
Marcellus Shale		6,871		—		—		6,871
Total reportable segments		71,964		10,783		6,762		89,509
All other segments		—		—		644		644
Total	$	71,964	$	10,783	$	7,406	$	90,153

	Three months ended September 30, 2019
	Gathering services and related fees		Natural gas, NGLs and condensate sales			Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	8,865	$	-		$	-	$	8,865
Williston Basin		16,685		1,878			2,555		21,118
DJ Basin		7,039		93			735		7,867
Permian Basin		986		3,797			102		4,885
Piceance Basin		30,120		1,733			1,258		33,111
Barnett Shale		11,286		4,828			1,706		17,820
Marcellus Shale		5,987		—			—		5,987
Total reportable segments		80,968		12,329			6,356		99,653
All other segments		—		(110	)		644		534
Total	$	80,968	$	12,219		$	7,000	$	100,187

	Nine months ended September 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	26,885	$	-	$	-	$	26,885
Williston Basin		47,145		12,413		9,054		68,612
DJ Basin		18,134		158		2,853		21,145
Permian Basin		7,617		13,537		481		21,635
Piceance Basin		79,987		1,932		3,394		85,313
Barnett Shale		30,865		7,206		4,437		42,508
Marcellus Shale		19,034		—		—		19,034
Total reportable segments		229,667		35,246		20,219		285,132
All other segments		—		—		1,931		1,931
Total	$	229,667	$	35,246	$	22,150	$	287,063

	Nine months ended September 30, 2019
	Gathering services and related fees			Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	23,951		$	-	$	-	$	23,951
Williston Basin		58,076			11,231		8,133		77,440
DJ Basin		14,784			279		2,776		17,839
Permian Basin		1,938			10,424		183		12,545
Piceance Basin		92,515			6,139		3,341		101,995
Barnett Shale		35,739			11,705		5,008		52,452
Marcellus Shale		18,081			—		—		18,081
Total reportable segments		245,084			39,778		19,441		304,303
All other segments		(2,045	)		28,660		363		26,978
Total	$	243,039		$	68,438	$	19,804	$	331,281

Contract balances. Contract assets relate to the Partnership’s rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from 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, 2020
	(In thousands)
Contract assets, January 1, 2020	$	3,902
Additions		16,442
Transfers out		(2,275	)
Contract assets, September 30, 2020	$	18,069

As of September 30, 2020, receivables with customers totaled $53.8 million and contract assets totaled $18.1 million and are included in the accounts receivable caption on the unaudited condensed consolidated balance sheets.

As of December 31, 2019, receivables with customers totaled $90.4 million and contract assets totaled $3.9 million and are included in the accounts receivable caption on the unaudited condensed consolidated balance sheets.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. The Partnership recognizes contract liabilities under these arrangements in revenue over the contract period. For the three months ended September 30, 2020 and 2019, the Partnership recognized $2.4 million and $2.4 million of gathering services and related fees, respectively, which are included in the contract liability balance as of the beginning of the period. For the nine months ended September 30, 2020 and 2019, the Partnership recognized $7.1 million and $7.8 million of gathering services and related fees, respectively, which

are included in the contract liability balance at the beginning of the period. See Note 7 – Deferred Revenue for additional details.

4. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	September 30, 2020		December 31, 2019
	(In thousands)
Gathering and processing systems and related equipment	$	2,197,087	$	2,182,950
Construction in progress		78,146		78,716
Land and line fill		10,440		10,137
Other		60,589		54,595
Total		2,346,262		2,326,398
Less accumulated depreciation		(505,978)		(443,909)
Property, plant and equipment, net	$	1,840,284	$	1,882,489

In March 2020, in connection with the cancellation of a compressor station project in the DJ Basin due to delays in customer drilling plans, the Partnership recorded an impairment charge of $3.6 million for the related soft project costs.

In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, in the first quarter of 2019, the Partnership performed a recoverability assessment of certain assets within these reporting segments, the results of which are described below.

In March 2019, the Partnership determined that certain processing plant assets in the DJ Basin related to its existing 20 MMcf/d plant would no longer be utilized due to the Partnership’s expansion plans for the Niobrara G&P system. Based on the results of the recoverability assessment and the conclusion that the carrying value was not fully recoverable, the Partnership recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019.

In March 2019, the Partnership determined that certain compressor station assets in the Barnett Shale were impaired and recorded an impairment charge of $10.2 million, comprised of a $9.7 million impairment of fixed assets and a $0.5 million impairment of rights-of-way.

Depreciation expense and capitalized interest follow.

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(In thousands)
Depreciation expense	$	21,537	$	19,474	$	64,899	$	58,160
Capitalized interest		1,449		1,391		2,268		5,752

5. GOODWILL

Goodwill. The Partnership evaluates goodwill for impairment annually on September 30^th. In 2019, the Partnership performed its annual goodwill impairment test for the Mountaineer Midstream reporting unit using a combination of the income and market approaches and determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, the Partnership recognized a goodwill impairment charge of $16.2 million for the three and nine months ended September 30, 2019. The Partnership had no goodwill on its balance sheet after September 30, 2019.

Fair Value Measurement. The Partnership’s impairment determinations, in the context of (i) its annual impairment evaluations and (ii) its other-than-annual impairment evaluations, involve significant assumptions and judgments, as discussed in the 2019 Annual Report. Differing assumptions regarding any of these inputs could have a significant effect on the 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.

6. EQUITY METHOD INVESTMENTS

Double E

The Partnership is responsible for leading the development, permitting and construction of the Double E Project. During the three and nine month periods ended September 30, 2020, the Partnership made cash investments of $12.4 million and $92.1 million, respectively, in the Double E Project.

For the three and nine months ended September 30, 2020, other than the investment activity noted above, Double E did not have any results of operations given that the Double E Project is currently under development.

Ohio Gathering

As of September 30, 2020 and December 31, 2019, the Partnership’s ownership interest in Ohio Gathering was 38.2% and 38.5%, respectively, and provided below is the September 30, 2020 reconciliation of the difference between the carrying amount of the Partnership’s interest in Ohio Gathering and the Partnership’s underlying investment per Ohio Gathering's books and records (in thousands).

Investment in Ohio Gathering, September 30, 2020	$	263,639
September cash distributions		3,870
Basis difference		218,757
Investment in Ohio Gathering (Books and records), August 31, 2020	$	486,266

7. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

	Total
	(In thousands)
Current deferred revenue, January 1, 2020	$	13,493
Additions		15,433
Less: revenue recognized		(11,099)
Current deferred revenue, September 30, 2020	$	17,827

A rollforward of noncurrent deferred revenue follows.

	Total
	(In thousands)
Noncurrent deferred revenue, January 1, 2020	$	38,709
Additions		18,402
Less: reclassification to current deferred revenue		(15,356)
Noncurrent deferred revenue, September 30, 2020	$	41,755

8. DEBT

Debt consisted of the following:

	September 30, 2020			December 31, 2019
	(In thousands)
Revolving Credit Facility: Summit Holdings' variable rate senior secured Revolving Credit Facility (2.90% at September 30, 2020 and 4.55% at December 31, 2019) due May 2022	$	808,500		$	677,000
ECP Loans: Summit Holdings' 8.00% senior secured term loans due March 2021		—			—
2022 Senior Notes: Summit Holdings' 5.5% senior unsecured notes due August 2022		234,047			300,000
Less: unamortized debt issuance costs ⁽¹⁾		(997	)		(1,686	)
2025 Senior Notes: Summit Holdings' 5.75% senior unsecured notes due April 2025		355,071			500,000
Less: unamortized debt issuance costs ⁽¹⁾		(3,055	)		(5,015	)
SMPH Term Loan: SMP Holdings' variable rate senior secured term loan (7.00% at September 30, 2020 and 7.80% at December 31, 2019) due May 2022		155,200			161,500
Less: unamortized debt issuance costs ⁽¹⁾		(2,724	)		(3,974	)
Total debt		1,546,042			1,627,825
Less: current portion		(155,200)			(5,546)
Total long-term debt	$	1,390,842		$	1,622,279

⁽¹⁾ Issuance costs are being amortized over the life of the SMPH Term Loan and the Senior Notes.

Revolving Credit Facility. The Partnership’s subsidiary, Summit Holdings, has a senior secured revolving credit facility (the “Revolving Credit Facility”) which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. At September 30, 2020, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 2.90% and the unused portion of the Revolving Credit Facility totaled $437.4 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of September 30, 2020 was approximately $172.0 million. As of and during the nine months ended September 30, 2020, we were in compliance with the Revolving Credit Facility's financial covenants. There were no defaults or events of default during the nine months ended September 30, 2020.

Significant updates to the Partnership’s indebtedness for the three and nine months ended September 30, 2020 included the following matters.

ECP Loans. On May 28, 2020, in connection with the closing of the GP Buy-In Transaction, Summit Holdings, entered into (i) a Term Loan Credit Agreement (the “ECP NewCo Term Loan Credit Agreement”), with SMP TopCo, LLC, a Delaware limited liability company and affiliate of ECP (“ECP NewCo”), as lender and administrative agent, and Mizuho Bank (USA) (“Mizuho”), as collateral agent, in a principal amount of $28.2 million (the “ECP NewCo Loan”), and (ii) a Term Loan Credit Agreement (the “ECP Holdings Term Loan Credit Agreement” and together with the ECP NewCo Term Loan Credit Agreement, the “ECP Term Loan Credit Agreements”), with ECP Holdings, as lender, and ECP NewCo, as administrative agent and Mizuho, as collateral agent, in a principal amount of $6.8 million (the “ECP Holdings Loan” and together with the ECP NewCo Loan, the “ECP Loans”). The ECP Loans were set to mature on March 31, 2021 and bore interest at a rate of 8.00% per annum, with the interest payment due at maturity of the ECP Loans. With borrowings under the Partnership’s Revolving Credit Facility, the Partnership fully repaid all amounts outstanding under the ECP Loans ($35 million of principal and $0.6 million of accrued interest) on August 7, 2020.

SMPH Term Loan. On April 17, 2020, the Partnership entered into a derivative financial instrument to convert a portion of its variable rate SMPH Term Loan to a fixed rate debt consisting of a 1% LIBOR interest rate cap for a fee of $0.2 million (exclusive of the applicable bank margin charged by our lender) on a $125.0 million notional amount

beginning April 30, 2020 and ending on April 30, 2022. The Partnership did not designate the interest rate cap for hedge accounting as defined by GAAP and recognized an unsettled gain of $0.1 million on the interest rate cap in the other income line item on our unaudited condensed consolidated statement of operations for the three and nine month periods ended September 30, 2020.

Liability Management Transactions. During the three and nine months ended September 30, 2020, the Partnership completed several liability management transactions, described below, that resulted in the early extinguishment of $210.8 million of the Partnership’s 2022 and 2025 Senior Notes.

Open Market Repurchases. During the nine months ended September 30, 2020, the Partnership made a number of open market repurchases of its 2022 and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $106.2 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”). Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest totaled $82.9 million and the Partnership recognized a $56.2 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

Tender Offers. In September 2020, the Partnership completed cash tender offers (the “Tender Offers”) to purchase a portion of the 2022 and 2025 Senior Notes. Upon concluding the Tender Offers, the Partnership repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million and the Partnership recognized a $23.3 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

SMPH Term Loan Restructuring. On September 29, 2020, SMP Holdings and the Partnership entered into the Transaction Support Agreement (the “TSA”) with an ad hoc group of SMP Holdings’ lenders under the $155.2 million SMPH Term Loan (the “Term Loan Lenders”) that will result in a consensual debt discharge and restructuring transaction (the “TL Restructuring”) of the full amount owed under SMPH Term Loan in exchange for (i) a cash payment of $26.5 million to the Term Loan Lenders, (ii) the execution of a strict foreclosure by the collateral agent under the SMPH Term Loan for the benefit of the Term Loan Lenders on the 34.6 million SMLP common units pledged as collateral under the SMPH Term Loan, and (iii) the payment of certain fees and expenses by the Partnership. Upon consummation of the TL Restructuring, which is expected to occur during the quarterly period ended December 31, 2020, the SMPH Term Loan will be fully satisfied and cease to exist. Upon closing of the TL Restructuring the Partnership will recognize a gain equal to the difference between the face value of the cancelled debt and the fair value of the total consideration transferred, including unamortized debt issuance costs, and certain direct transaction costs related to the restructuring. As a result of the TL Restructuring, at September 30, 2020 the Partnership classified the SMPH Term Loan as current. Concurrently with the closing of the TL Restructuring, the Partnership will make a $26.5 million cash payment on the Deferred Purchase Price Obligation to SMP Holdings and fully settle the obligation.

Gain on Extinguishment of Debt. The Partnership recognized a $78.9 million gain on extinguishment of debt during the nine months ended September 30, 2020, primarily as the result of the its Open Market Repurchases and its Tender Offers.

	ECP Loan Repayment			Open Market Repurchases						Tender Offers						Total
				2022			2025			2022			2025
				Senior Notes			Senior Notes			Senior Notes			Senior Notes
	(in thousands)
Gain on repurchases of Senior Notes	$	-		$	11,554		$	46,003		$	9,223		$	15,479		$	82,259
Debt issue costs		(361	)		(143	)		(965	)		(125	)		(351	)		(1,945	)
Transaction cost		(249	)		(105	)		(105	)		(465	)		(465	)		(1,389	)
Gain (loss) on extinguishment	$	(610	)	$	11,306		$	44,933		$	8,633		$	14,663		$	78,925

9. FINANCIAL INSTRUMENTS

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

	September 30, 2020				December 31, 2019
	Carrying Value, Net		Estimated fair value (Level 2)		Carrying Value, Net		Estimated fair value (Level 2)
	(In thousands)
2022 Senior Notes	$	233,050	$	169,684	$	298,314	$	266,750
2025 Senior Notes		352,016		204,758		494,985		382,708

The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to their floating interest rates. The fair value for the 2022 and 2025 Senior Notes is based on an average of nonbinding broker quotes. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the 2022 and 2025 Senior Notes.

10. PARTNERS' CAPITAL AND MEZZANINE CAPITAL

A rollforward of the number of common units follows.

	Common Units
Units, December 31, 2019⁽¹⁾		45,318,866
Net units issued under the SMLP LTIP		1,028,654
Impact of GP Buy-In Transaction		(1,990,303	)
Preferred Unit Exchange		12,267,670
Units, September 30, 2020⁽¹⁾		56,624,887

⁽¹⁾ As a result of the GP Buy-In Transaction, the Partnership recast its historical financial statements, which resulted in a recasted SMLP common limited partner unit count of 45.3 million units at December 31, 2019. Prior to the GP Buy-In Transaction, the SMLP common limited partner unit count was 94.5 million units, and after adjusting for (i) the effect of 1.0 million SMLP units issued following the closing of the GP Buy-In transaction through September 30, 2020 for the SMLP LTIP, (ii) the 12.3 million SMLP common units issued in the Exchange Offer, and (iii) the GP Buy-In Transaction which included the Partnership acquiring SMP Holdings which owns the 34.6 million SMLP units pledged under the SMPH Term Loan, the 10.7 million SMLP units not pledged under the SMPH Term Loan, and the 5.9 million SMLP units owned by ECP, the SMLP common limited partner unit count would have been an otherwise identical 56.6 million SMLP common units at September 30, 2020.

GP Buy-In Transaction. The purchase price for the SMLP common units reflected in the unaudited condensed consolidated statement of partners’ capital for the nine months ended September 30, 2020 is comprised of the (i) the $35.0 million cash payment to ECP, (ii) the $2.3 million fair value for the issuance of 10,000,000 warrants, and (iii) $6.8 million of advisory fees and other direct costs related to closing the GP Buy-In Transaction.

Series A Preferred Units. In 2017, the Partnership issued 300,000 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 2019 Annual Report. In connection with the GP Buy-In Transaction, the Partnership suspended its distributions to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. On June 18, 2020, the Partnership, commenced an offer to exchange any and all of its Series A Preferred Units for newly issued SMLP common units (the “Exchange Offer”). On July 28, 2020, the Exchange Offer expired and the Partnership exchanged 62,816 Series A Preferred Units for 12,267,670 SMLP common units, net of units withheld for tax withholdings. As of September 30, 2020, the Partnership had 237,184 Series A Preferred Units outstanding.

Subsidiary Series A Preferred Units. The Partnership issued 53,784 Subsidiary Series A Preferred Units during the nine months ended September 30, 2020 at a price of $1,000 per unit and has cumulatively issued 83,842 Subsidiary Series A Preferred Units since the instrument’s initial issuance in December 2019. Net proceeds received during the nine months ended September 30, 2020 totaled $48.7 million (after deducting underwriting discounts and offering expenses) and were used to fund the Partnership’s share of capital expenditures associated with the Double E Project. The proceeds associated with the issuance of Subsidiary Series A Preferred Units are restricted for funding the Double E Project and are classified as restricted cash in the accompanying unaudited condensed consolidated balance sheets.

The Partnership records its Subsidiary Series A Preferred Units at fair value upon issuance, net of issuance costs, and subsequently records an effective interest method accretion amount each reporting period to accrete the carrying value to a most probable redemption value that is based on a predetermined internal rate of return measure. The Partnership also elected to make payment-in-kind (“PIK”) distributions to holders of the Subsidiary Series A Preferred Units during the nine months ended September 30, 2020 and these PIK distributions increase the liquidation preference on each Subsidiary Series A Preferred Unit. Ultimately, Net Income (Loss) Attributable to common limited partners includes adjustments for PIK distributions and redemption accretion.

If the Subsidiary Series A Preferred Units were redeemed on September 30, 2020, the redemption amount would be $104.8 million when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Subsidiary Series A Preferred Unit agreement. The following table shows the change in our Subsidiary Series A Preferred Unit balance from December 31, 2019 to September 30, 2020:

	September 30, 2020
	(in thousands)
Balance at December 31, 2019	$	27,450
New issuances		50,000
PIK distributions		3,784
Issuance costs		(1,290	)
Redemption accretion		5,856
Balance at September 30, 2020⁽¹⁾	$	85,800

⁽¹⁾ Amount is net of $3.9 million of issuance costs at September 30, 2020.

Warrants. On May 28, 2020 and in connection with the GP Buy-In Transaction, the Partnership issued (i) a warrant to purchase up to 8,059,609 SMLP common units to ECP NewCo (the “ECP NewCo Warrant”) and (ii) a warrant to purchase up to 1,940,391 SMLP common units to ECP Holdings (the “ECP Holdings Warrant” and together with the ECP NewCo Warrant, the “ECP Warrants”). The exercise price under the ECP Warrants is $1.023 per SMLP common unit and the Partnership may issue a maximum of 10,000,000 SMLP common units under the ECP Warrants.

Upon exercise of the ECP Warrants, each of ECP NewCo and ECP Holdings may receive, at its election: (i) a number of SMLP common units equal to the number of SMLP common units for which the ECP Warrants are being exercised, if exercising the ECP Warrants by cash payment of the exercise price; (ii) a number of SMLP common units equal to the product of the number of common units being exercised multiplied by (a) the difference between the average of the daily volume-weighted average price (“VWAP”) of the SMLP common units on the New York Stock Exchange (the “NYSE”) on each of the three trading days prior to the delivery of the notice of exercise (the “VWAP Average”) and the exercise price (the “VWAP Difference”), divided by (b) the VWAP Average; and/or (iii) an amount in cash, to the extent that the Partnership’s leverage ratio would be at least 0.5x less than the maximum applicable ratio set forth in the Revolving Credit Facility, equal to the product of (a) the number of SMLP common units exercised and (b) the VWAP Difference, subject to certain adjustments under the ECP Warrants.

The ECP Warrants are subject to standard anti-dilution adjustments for stock dividends, stock splits (including reverse splits) and recapitalizations and are exercisable at any time on or before May 28, 2023. Upon exercise of the ECP Warrants, the proceeds to the holders of the ECP Warrants, whether in the form of cash or common units, will be capped at $2.00 per SMLP common unit above the exercise price.

At issuance the ECP Warrants were valued at $2.3 million using a Black-Scholes model and accounted for as a liability instrument. At September 30, 2020, the ECP Warrants were valued at $1.5 million.

SMLP General Partner and Incentive Distribution Rights (“IDR”) Exchange. In March 2019, and prior to the GP Buy-In Transaction, a subsidiary of Summit Investments cancelled its IDR agreement with SMLP and converted its 2% economic general partner interest to a non-economic general partner interest in exchange for 8,750,000 SMLP common units. This exchange is reflected in the Consolidated Statements of Partners’ Capital as a reduction to noncontrolling interest and an increase to Partners’ Capital.

Cash Distributions Paid and Declared. Prior to the GP Buy-In Transaction, SMLP paid the following per-unit distributions during the three and nine month periods ended September 30 (all payments represent per-unit distributions based on the SMLP common units outstanding prior to the GP Buy-In Transaction):

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Per-unit distributions to unitholders	$	—	$	0.2875	$	0.125	$	1.1500

In connection with the GP Buy-In Transaction, the Partnership suspended its distributions to holders of its common units, commencing with respect to the quarter ending March 31, 2020.

With respect to our Subsidiary Series A Preferred Units relating to the three and nine months ended September 30, 2020, the Partnership declared a PIK of the quarterly distribution, which resulted in the issuance of 45 Subsidiary Series A Preferred Units and 1,442 Subsidiary Series A Preferred Units, respectively. This PIK amount equates to a distribution of $32.1133 and $17.5099 per Subsidiary Series A Preferred Unit for the three and nine months ended September 30, 2020, respectively, or $70 on an annualized basis. In addition, the Partnership issued approximately 38 Subsidiary Series A Preferred Units related to the remaining undrawn commitment (as defined in the underlying agreement with TPG Energy Solutions Anthem, L.P.) as of and for the nine months ended September 30, 2020.

11. EARNINGS PER UNIT

The following table details the components of EPU.

	Three months ended September 30,					Nine months ended September 30,
	2020		2019			2020		2019
	(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	$	25,629	$	(789	)	$	89,386	$	(11,130	)
Less:
Net income attributable to Series A Preferred Units		6,481		7,125			20,731		21,375
Net income attributable to Subsidiary Series A Preferred Units		7,298		—			9,640		—
Add:
Deemed capital contribution from Series A Preferred Unit Exchange Offer		54,945		—			54,945		—
Net income (loss) attributable to common limited partners	$	66,795	$	(7,914	)	$	113,960	$	(32,505	)

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic⁽¹⁾		51,974		45,319			47,331		45,319
Effect of nonvested phantom units		1,676		—			1,451		—
Weighted-average common units outstanding – diluted		53,650		45,319			48,782		45,319

Net Income (Loss) per limited partner unit:
Common unit – basic	$	1.29	$	(0.17	)	$	2.41	$	(0.72	)
Common unit – diluted	$	1.25	$	(0.17	)	$	2.34	$	(0.72	)

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		4,031		176			3,353		70

⁽¹⁾ As a result of the GP Buy-In Transaction, our historical results are those of Summit Investments. The number of common units of 45.3 million as of September 30, 2019 represents those of Summit Investments and has been used for the earnings per unit calculations presented herein.

As discussed in Note 8 - Debt, the SMPH Term Loan is secured by 34.6 million SMLP common units owned by SMP Holdings. These common units are not included in the calculation of EPU because they are not deemed contingently issuable under GAAP. Upon closing the TL Restructuring, the 34.6 million SMLP common units pledged under the SMPH Term Loan will be considered outstanding and included in the calculation of EPU.

12. SUPPLEMENTAL CASH FLOW INFORMATION

	Nine months ended September 30,
	2020		2019
	(In thousands)
Supplemental cash flow information:
Cash interest paid	$	62,441	$	66,435
Less capitalized interest		2,268		5,752
Interest paid (net of capitalized interest)	$	60,173	$	60,683

Cash paid for taxes	$	—	$	150

Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	10,233	$	22,166
Warrant issuance for GP Buy-In Transaction		2,300		—
Asset contribution to an equity method investment		—		23,643
Right-of-use assets relating to ASC Topic 842		2,964		5,448
Accretion of Subsidiary Series A Preferred Units		5,856		—

13. UNIT-BASED AND NONCASH COMPENSATION

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

•

In March 2020, the Partnership granted 3,811,301 phantom units and associated distribution equivalent rights to employees in connection with the Partnership’s annual incentive compensation award cycle. These awards had a grant date fair value of $0.55 and vest ratably over a three-year period.

•

In March 2020, the Partnership issued 549,450 common units to the Partnership’s three independent directors in connection with their annual compensation plan.

•

In June 2020, the Partnership issued 187,500 common units to three new independent directors in connection with their annual compensation plan.

•

During the nine months ended September 30, 2020, 0.8 million phantom units vested.

•

In March 2020, the Partnership increased the number of common units authorized under the SMLP LTIP to 15,000,000 common units and extended the term of the SMLP LTIP for 10 years.

•

As of September 30, 2020, approximately 6.3 million common units remained available for future issuance under the SMLP LTIP.

14. COMMITMENTS AND CONTINGENCIES

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

In 2015, the Partnership 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 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. The pollution liability policy was exhausted in 2015.

A rollforward of the Partnership’s undiscounted accrued environmental remediation liabilities follows.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2020	$	4,651
Payments made		(1,095	)
Accrued environmental remediation, September 30, 2020	$	3,556

As of September 30, 2020, the Partnership has 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 expected to be incurred subsequent to September 30, 2021. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts have been discounted to its present value.

Prior to the GP Buy-In Transaction, Summit Investments and SMP Holdings indemnified the Partnership for certain obligations and liabilities related to the incident. As a result of the GP Buy-In Transaction, the Partnership continues to be indemnified by Summit Investments and SMP Holdings, both subsidiaries of the Partnership, but is no longer indemnified for these obligations by a third party that is not a subsidiary of the Partnership.

The U.S. Department of Justice issued grand jury subpoenas to the Partnership requesting certain materials related to the Meadowlark Midstream rupture. Based on information currently available to the Partnership, the Partnership believes a loss for claims and/or actions arising from the Meadowlark Midstream rupture is probable. Due to the complexity surrounding the resolution of the Meadowlark Midstream rupture, the Partnership is not able to reasonably estimate the extent of the Partnership’s loss for this matter, or to express an opinion regarding the ultimate outcome. Any such loss, if incurred, could be material.

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.

15. DISPOSITIONS AND RESTRUCTURING

Tioga Midstream Disposition. In February 2019, the Partnership entered into two Purchase and Sale Agreements (the “Tioga PSAs”) with Hess Infrastructure Partners LP and Hess North Dakota Pipelines LLC (collectively, “Hess Infrastructure”), pursuant to which the Partnership agreed to sell the Tioga Midstream system to Hess Infrastructure for a combined cash purchase price of $90 million, subject to adjustments as provided in the Tioga PSAs (the “Tioga Midstream Sale”). On March 22, 2019, the Partnership closed the Tioga Midstream Sale and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in the Partnership’s unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

Restructuring Activities. As of December 31, 2019, the Partnership had $3.3 million of unpaid employee severance costs related to 2019 restructuring initiatives that resulted in certain management, facility and organizational changes. During the three and nine month periods ended September 30, 2020, the Partnership’s 2019 restructuring initiatives resulted in additional restructuring costs of $0.1 million and $3.4 million, respectively. The Partnership paid out $6.4 million of these 2019 restructuring costs during the nine months ended September 30, 2020 and has a $0.3 million current liability for unpaid employee severance costs at September 30, 2020 related to these 2019 restructuring initiatives. The 2019 restructuring activities primarily consisted of employee-related costs and consulting costs in support of the restructuring initiatives. Restructuring costs are included within the general and administrative expense caption on the condensed consolidated statement of operations.

16. SEGMENT INFORMATION

As of September 30, 2020, the Partnership’s 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, Bison Midstream and Meadowlark Midstream;

•

the DJ Basin, which is served by Niobrara G&P;

•

the Permian Basin, which is served by Summit Permian;

•

the Piceance Basin, which is served by Grand River;

•

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

•

the Marcellus Shale, which is served by Mountaineer Midstream.

Until March 22, 2019, the Partnership owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 15 – Dispositions and Restructuring to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream.

Each of the Partnership’s reportable segments provide midstream services in a specific geographic area and reflect the way in which the Partnership internally reports the financial information used to make decisions and allocate resources in connection with the Partnership’s operations.

For the three and nine months ended September 30, 2020, other than the investment activity described in Note 6 – Equity Method Investments, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the fourth quarter of 2021.

Corporate and Other represents those results that are: (i) not specifically attributable to a reportable segment; (ii) not individually reportable (such as Double E); or (iii) that have not been allocated to the Partnership’s reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, certain natural gas and crude oil marketing services, construction management fees related to the Double E Project and transaction costs.

Assets by reportable segment follow.

	September 30, 2020		December 31, 2019
	(In thousands)
Assets⁽¹⁾:
Utica Shale	$	208,090	$	206,368
Ohio Gathering		263,639		275,000
Williston Basin		443,506		452,152
DJ Basin		204,206		205,308
Permian Basin		167,707		185,708
Piceance Basin		596,148		631,140
Barnett Shale		349,254		350,638
Marcellus Shale		182,900		184,631
Total reportable segment assets		2,415,450		2,490,945
Corporate and Other		158,029		83,153
Total assets	$	2,573,479	$	2,574,098

⁽¹⁾

At September 30, 2020, Corporate and Other included $125.4 million relating to our investment in Double E (included in the Investment in equity method investees caption of the unaudited condensed consolidated balance sheet). At December 31, 2019, Corporate and Other included $34.7 million relating to our investment in Double E.

Segment adjusted EBITDA by reportable segment follows.

	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	7,453	$	7,864	$	24,074	$	20,697
Ohio Gathering		7,129		10,435		22,582		29,584
Williston Basin		11,713		13,840		40,632		49,224
DJ Basin		4,766		6,554		15,016		12,043
Permian Basin		893		210		4,302		(996	)
Piceance Basin		21,503		24,044		66,794		74,627
Barnett Shale		7,205		10,901		24,475		33,483
Marcellus Shale		6,022		4,958		16,230		14,735
Total of reportable segments' measures of profit	$	66,684	$	78,806	$	214,105	$	233,397

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 follows.

	Three months ended September 30,						Nine months ended September 30,
	2020			2019			2020			2019
	(In thousands)
Reconciliation of income (loss) before income taxes and income (loss) from equity method investees to total of reportable segments' measures of profit:
Income (loss) before income taxes and income (loss) from equity method investees	$	25,132		$	(10,431	)	$	78,862		$	(45,757	)
Add:
Corporate and Other expense		6,874			7,119			28,484			32,024
Interest expense		19,018			23,462			64,836			68,547
Gain on early extinguishment of debt		(24,690	)		—			(78,925	)		—
Depreciation and amortization⁽¹⁾		29,739			27,677			89,505			83,030
Proportional adjusted EBITDA for equity method investees		7,129			10,435			22,582			29,584
Adjustments related to MVC shortfall payments		2,292			3,534			(859	)		2,868
Adjustments related to capital reimbursement activity		(328	)		(145	)		(776	)		(1,906	)
Unit-based and noncash compensation		1,622			1,291			6,191			5,370
Gain on asset sales, net		(104	)		(347	)		(270	)		(1,595	)
Long-lived asset impairment		—			—			4,475			45,021
Goodwill impairment		—			16,211			—			16,211
Total of reportable segments' measures of profit	$	66,684		$	78,806		$	214,105		$	233,397

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

17. SUBSEQUENT EVENTS

Open Market Repurchases of 2025 Senior Notes. In October 2020, the Partnership repurchased an additional $95.6 million of the outstanding 2025 Senior Notes for total cash consideration of $64.8 million.

TL Restructuring. In October 2020, the Partnership obtained consents for the TL Restructuring from 100% of the Term Loan Lenders and subsequently filed a Form S-1 registration statement with the Securities and Exchange Commission on November 3, 2020 to register the 34.6 million SMLP common units to be issued to the lenders of the SMPH Term Loan upon consummation of the TL Restructuring. Once the Form S-1 registration statement becomes effective and administrative procedures are performed, the Partnership will close the TL Restructuring and recognize a gain on early debt extinguishment.

Reverse Unit Split. On October 15, 2020, the Board of Directors of the General Partner authorized a reverse unit split (the “Reverse Unit Split”) of the Partnership’s common units. The exchange ratio of the Reverse Unit Split is 1-for-15 and will be effective on November 9, 2020. The common units will begin trading on a split-adjusted basis on November 10, 2020. The Reverse Unit Split is intended to, among other things, increase the per unit trading price of the Partnership’s common units to satisfy the $1.00 minimum bid price requirement for continued listing on the NYSE. As a result of the Reverse Unit Split, each 15 pre-split common units will automatically be combined into one issued and outstanding common unit without any action on the part of the unitholder. Any fractional common units issued as a result of the Reverse Unit Split will be rounded to the nearest whole number of common units. Once effective, the number of outstanding shares of common units will be reduced from 56,624,887 common units as of October 30, 2020 to 3,774,992 common units.

FERC Approval. In October 2020, Double E received Federal Energy Regulatory Commission ("FERC") approval of its application to construct and operate the Double E Pipeline Project, pursuant to Section 7(c) of the Natural Gas Act. Upon fulfilling certain remaining requirements, including finalizing a right-of-way grant from the Bureau of Land Management and filing an implementation plan with the FERC, Double E expects to receive FERC's notice to proceed with construction.

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

This 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 periods since December 31, 2019. 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 2019 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 value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States.

We classify our midstream energy infrastructure assets into two categories:

•

Core Focus Areas – core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas.

•

Legacy Areas – production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas.

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances 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 the following activities that directly expose us to

fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the three and nine months ended September 30, 2020, these additional activities accounted for approximately 12% of total revenues.

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 earn 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, 2020 and 2019" section included herein.

	Three months ended September 30,						Nine months ended September 30,
	2020			2019			2020			2019
	(In thousands)
Net income (loss)	$	25,629		$	(11,129	)	$	86,112		$	(48,381	)
Reportable segment adjusted EBITDA
Utica Shale	$	7,453		$	7,864		$	24,074		$	20,697
Ohio Gathering		7,129			10,435			22,582			29,584
Williston Basin		11,713			13,840			40,632			49,224
DJ Basin		4,766			6,554			15,016			12,043
Permian Basin		893			210			4,302			(996	)
Piceance Basin		21,503			24,044			66,794			74,627
Barnett Shale		7,205			10,901			24,475			33,483
Marcellus Shale		6,022			4,958			16,230			14,735

Net cash provided by operating activities	$	41,436		$	43,043		$	146,807		$	127,617
Capital expenditures ⁽¹⁾		7,886			40,571			35,312			151,663
Investment in equity method investee		12,344			5,409			92,072			11,330

Net cash distributions to noncontrolling interest SMLP unitholders	$	—		$	13,829		$	6,037		$	55,029
Series A Preferred Unit distributions		—			—			—			14,250
Net borrowings under Revolving Credit Facility		75,500			27,000			131,500			134,000
Repayments on SMPH term loan		—			(5,750	)		(6,300	)		(59,500	)
Open Market Repurchases of 2022 and 2025 Senior Notes (Note 8)		(6,137	)		—			(82,844	)		—
Tender Offers of 2022 and 2025 Senior Notes (Note 8)		(48,712	)		—			(48,712	)		—
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs ⁽²⁾		—			—			48,710			—
Purchase of common units in GP Buy-In Transaction		—			—			(41,778	)		—

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

⁽²⁾ Reflects proceeds from the issuance of Subsidiary Series A Preferred Units.

Key matters for three and nine months ended September 30, 2020. The following items are reflected in our financial results:

•

GP Buy-In Transaction. On May 28, 2020, we closed the GP Buy-In Transaction. Refer to Note 1 – Organization, Business Operations and Presentation and Consolidation for details.

•

Series A Preferred Unit Exchange Offer. On June 18, 2020, we commenced an offer to exchange any and all of our Series A Preferred Units for newly issued common units (the “Exchange Offer”). On July 28, 2020 the Exchange Offer expired and the Partnership exchanged 62,816 Series A Preferred Units for 12,267,670 common units, net of units withheld for tax withholdings.

•

Open Market Repurchase of Senior Notes. During the nine months ended September 30, 2020, the Partnership made Open Market Repurchases that resulted in the extinguishment of $32.4 million of its outstanding 2022 Senior Notes and $106.2 million of 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $82.9 million and the Partnership recognized a $56.2 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

•

Tender Offers. In September 2020, the Partnership completed Tender Offers initiated in August 2020 to purchase a portion of the 2022 and 2025 Senior Notes. Upon concluding the Tender Offer, the Partnership repurchased $33.5 million of the 2022 Senior Notes and $38.7 million of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million and the Partnership recognized a $23.3 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

•

TL Restructuring. On September 29, 2020, we signed the TSA for the TL Restructuring. Refer to Note 8 – Debt and Note 16 – Subsequent Events for further details on the TL Restructuring. The TL Restructuring had not closed as of September 30, 2020 and our financial results do not include a gain on the extinguishment of debt related to the TL Restructuring.

Key matters for the three and nine months ended September 30, 2019. The following items are reflected in our financial results:

•

Goodwill Impairment. In September 2019, in connection with our annual impairment evaluation, we determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value and we recognized a goodwill impairment charge of $16.2 million for the three and nine months ended September 30, 2019.

•

Double E Project. In June 2019, we decided to proceed with the Double E Project after securing firm 10-year take-or-pay commitments for a substantial majority of the pipeline’s initial throughput capacity of 1.35 billion cubic feet of gas per day and executing the JV Agreement with an affiliate of Double E’s foundation shipper.

In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. We own a majority interest in the Double E Project and are leading efforts to develop, permit and construct the pipeline. Upon commissioning, we will operate the pipeline.

•

Disposition. In March 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

•

Asset Impairment. In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a

recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our existing 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets were impaired and recorded an impairment charge of $10.2 million.

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 availability and cost of capital;

•

Shifts in operating costs and inflation; and

•

Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil.

We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it has impacted and will impact our customers, employees, supply chain and distribution network. While COVID-19 did not have a material adverse effect on our reported results for the first nine months of 2020, we are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. Given the dynamic nature of the COVID-19 pandemic and related market conditions, we cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on our business. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be harmed, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.

In addition, the COVID-19 pandemic has significantly reduced the global demand for oil and natural gas. This significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, or OPEC, and other foreign, oil-exporting countries, and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, extended cuts again in June and cuts its long-term forecast for oil demand growth in October, there is no assurance that the agreement will continue to be observed by its members and the responses of oil and gas producers to the

lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. After increasing supply through the summer of 2020, certain OPEC members recently announced price cuts for October, potentially signaling continued pressure on demand. Such responses could cause our pipelines and storage tanks and other third-party storage facilities to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products.

Over the past several months, we have collaborated extensively with our customer base regarding production reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given continued volatility in market conditions since March 2020, and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity and the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. For example, beginning in June 2020, in the Utica Shale, a customer curtailed in excess of 150 MMcf/d of production which impacted volume throughput across our gathering system and the financial results of that segment through the middle of the third quarter of 2020, when more favorable natural gas prices returned and that customer reversed that particular production curtailment. We also recently amended gathering contracts with two key Williston Basin customers to extend the terms of the gathering agreement acreage dedications, in exchange for a modest gathering fee concession. We expect 2020 total capital expenditures to range from $55 million to $65 million.

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 2019 Annual Report.

How We Evaluate Our Operations

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. For additional information see Note – 16 Segment Information.

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, 2020.

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 2019 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 – Summary of Significant Accounting Policies.

Results of Operations

Consolidated Overview for the Three and Nine Months Ended September 30, 2020 and 2019

The following table presents certain consolidated financial and operating data.

	Three months ended September 30,						Nine months ended September 30,
	2020			2019			2020			2019
	(In thousands)
Revenues:
Gathering services and related fees	$	71,964		$	80,968		$	229,667		$	243,039
Natural gas, NGLs and condensate sales		10,783			12,219			35,246			68,438
Other revenues		7,406			7,000			22,150			19,804
Total revenues		90,153			100,187			287,063			331,281
Costs and expenses:
Cost of natural gas and NGLs		8,632			7,472			22,945			50,802
Operation and maintenance		22,168			26,231			65,131			74,771
General and administrative		10,561			10,029			39,908			38,979
Depreciation and amortization		29,505			27,443			88,801			82,044
Transaction costs		726			129			1,944			2,562
Gain on asset sales, net		(104	)		(347	)		(270	)		(1,595	)
Long-lived asset impairment		—			—			4,475			45,021
Goodwill Impairment		—			16,211			—			16,211
Total costs and expenses		71,488			87,168			222,934			308,795
Other income		795			12			644			304
Interest expense		(19,018	)		(23,462	)		(64,836	)		(68,547	)
Gain on early extinguishment of debt		24,690			—			78,925			—
Income (loss) before income taxes and equity method investment income (loss)		25,132			(10,431	)		78,862			(45,757	)
Income tax benefit (expense)		(298	)		(21	)		104			(1,427	)
Income (loss) from equity method investees		795			(677	)		7,146			(1,197	)
Net income (loss)	$	25,629		$	(11,129	)	$	86,112		$	(48,381	)

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,392			1,394			1,354			1,410
Aggregate average daily throughput - liquids (Mbbl/d)		69			105			81			101

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

Volumes – Gas. Natural gas throughput volumes decreased 2 MMcf/d for the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily reflecting:

•

a volume throughput increase of 62 MMcf/d for the Utica Shale segment.

•

a volume throughput increase of 47 MMcf/d for the Marcellus Shale segment.

•

a volume throughput increase of 14 MMcf/d for the Permian Basin segment.

•

a volume throughput decrease of 85 MMcf/d for the Piceance Basin segment.

•

a volume throughput decrease of 39 MMcf/d for the Barnett Shale segment.

Natural gas throughput volumes decreased 56 MMcf/d for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily reflecting:

•

a volume throughput decrease of 94 MMcf/d for the Piceance Basin segment.

•

a volume throughput decrease of 40 MMcf/d for the Barnett Shale segment.

•

a volume throughput increase of 51 MMcf/d for the Utica Shale segment.

•

a volume throughput increase of 16 MMcf/d for the Permian Basin segment.

•

a volume throughput increase of 8 MMcf/d for the Marcellus Shale segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 36 Mbbl/d and 20 Mbbl/d for the three and nine months ended September 30, 2020, respectively, compared to the three and nine months ended September 30, 2019.

For additional information on volumes, see the "Segment Overview for the Three and Nine Months Ended September 30, 2020 and 2019" section herein.

Revenues. Total revenues decreased $10.0 million during the three months ended September 30, 2020 compared to the prior year period primarily comprised of a $9.0 million decrease in gathering services and related fees and a $1.4 million decrease in natural gas, NGLs and condensate sales.

Gathering Services and Related Fees. Gathering services and related fees decreased $9.0 million compared to the three months ended September 30, 2019, primarily reflecting:

•

a $3.5 million decrease in gathering services and related fees in the Piceance Basin related to lower volume throughput due to a lack of drilling and completion activity and natural production declines in addition to the sale of certain assets from our Red Rock Gathering system in December 2019.

•

a $5.7 million decrease in gathering services and related fees in the Williston Basin due to lower liquids throughput associated with natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

•

a $0.7 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019.

•

a $0.5 million decrease in gathering services and related fees in the Utica Shale as a result of natural production declines on existing wells and temporary production curtailments beginning in June 2020, partially offset by the completion of new wells throughout 2019 and in the first half of 2020.

•

a $1.0 million decrease in gathering services and related fees in the DJ Basin as a result of natural production declines and limited drilling and completion activity associated with a reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019.

•

a $1.6 million increase in gathering services and related fees in the Permian Basin due to higher volumes from wells connected in the fourth quarter of 2019 and first quarter of 2020 and a more favorable volume and gathering rate mix from customers.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $1.4 million compared to the three months ended September 30, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services.

Total revenues decreased $44.2 million during the nine months ended September 30, 2020 compared to the prior year period primarily comprised of a $33.2 million decrease in natural gas, NGLs and condensate sales and a $13.4 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $13.4 million compared to the nine months ended September 30, 2019, primarily reflecting:

•

a $12.5 million decrease in gathering services and related fees in the Piceance Basin related to lower volume throughput due to a lack of drilling and completion activity and natural production declines in addition to the sale of certain assets from our Red Rock Gathering system in December 2019.

•

a $10.9 million decrease in gathering services and related fees in the Williston Basin primarily due to lower liquids throughput associated with natural production declines and, beginning in the second quarter of 2020, temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic. The decrease was also due to a $1.5 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, the 2019 financial results of which are included for the period from January 1, 2019 through March 22, 2019.

•

a $4.9 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019. Also impacting 2020 revenues was the presentation of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019, which decreased gathering services and related fees by $1.7 million.

•

a $3.4 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

•

a $5.7 million increase in gathering services and related fees in the Permian Basin due to higher volume growth from ongoing drilling and completion activity and a more favorable volume and gathering rate mix from customers.

•

a $2.9 million increase in gathering services and related fees in the Utica Shale as a result of the completion of new wells throughout 2019 and in the first nine months of 2020, and a more favorable volume and gathering rate mix from customers partially offset by natural production declines on existing wells.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $33.2 million compared to the nine months ended September 30, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $27.9 million decrease in natural gas, NGL and condensate purchases.

Costs and Expenses. Total costs and expenses decreased $15.7 million during the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a $16.2 million decrease from a noncash goodwill impairment charge in 2019 and a $4.1 million decrease in operation and maintenance expense partially offset by a $2.1 million increase in depreciation and amortization expense and a $1.2 million increase in natural gas, NGLs and condensate purchases.

Total costs and expenses decreased $85.7 million during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily due to the impact of: (i) the March 2019 recognition of a $34.9 million and $10.2 million long-lived asset impairment in the DJ Basin and Barnett Shale, respectively, (ii) the September of 2019 recognition of a $16.2 million noncash goodwill impairment charge in the Marcellus Shale, (iii) a $27.9 million decrease in natural gas, NGLs and condensate purchases and (iv) a $9.6 million decrease in operating and maintenance expense, partially offset by (v) the March 2020 recognition of a $3.6 million long-lived asset impairment in the DJ Basin and (vi) a $6.8 million increase in depreciation and amortization expense.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $1.2 million for the three months ended September 30, 2020 and decreased $27.9 million for the nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.

Operation and Maintenance. Operation and maintenance expense decreased $4.1 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a $1.4 million decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives and a $2.0 million decrease in general operating expenses.

Operation and maintenance expense decreased $9.6 million for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily due to a $4.1 million decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives, a $1.5 million decrease in property taxes and a $2.8 million decrease in remediation expense.

General and Administrative. General and administrative expense increased $0.5 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a $0.3 million increase in professional service fees and a $0.1 million increase in restructuring expenses.

General and administrative expense increased $0.9 million compared to the nine months ended September 30, 2019, primarily due to a $3.4 million increase in restructuring expenses, $1.5 million increase in deal costs and a $2.0 million increase in professional service fees, partially offset by a $6.1 million decrease in compensation expense primarily associated with lower headcount from our cost cutting initiatives.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to the acceleration of depreciation on certain Williston Basin assets.

Transaction Costs. The increase in transaction costs recognized during the three months ended September 30, 2020 compared to the three months ended September 30, 2019 was primarily due to costs associated with the GP Buy-In Transaction.

The decrease in transaction costs recognized during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was due to financial advisory costs incurred in 2019.

Interest Expense. The decrease in interest expense for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to our liability management initiatives which included our Open Market Repurchases and Tender Offers, partially offset by a higher outstanding balance on the Revolving Credit Facility.

Gain on early extinguishment of debt. The gain on early extinguishment of debt is primarily a result of our Open Market Repurchases and Tender Offers that resulted in a $78.9 million gain on extinguishment of debt during the nine months ended September 30, 2020 (Details below).

	ECP Loan Repayment			Open Market Repurchases						Tender Offers						Total
				2022			2025			2022			2025
				Senior Notes			Senior Notes			Senior Notes			Senior Notes
	(in thousands)
Gain/(loss) on face value of 2022 and 2025 Senior Notes	$	-		$	11,554		$	46,003		$	9,223		$	15,479		$	82,259
Debt issue costs		(361	)		(143	)		(965	)		(125	)		(351	)		(1,945	)
Transaction cost		(249	)		(105	)		(105	)		(465	)		(465	)		(1,389	)
Gain (loss) on extinguishment	$	(610	)	$	11,306		$	44,933		$	8,633		$	14,663		$	78,925

Segment Overview for the Three and Nine Months Ended September 30, 2020 and 2019

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,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		352		290	21%		330		279	18%

Volume throughput increased compared to the three months ended September 30, 2019, as a result of the completion of new wells throughout 2019, and in the first half of 2020, partially offset by natural production declines from existing wells and temporary production curtailments beginning in June 2020.

Volume throughput increased compared to the nine months ended September 30, 2019, as a result of the completion of new wells throughout 2019, and in the first half of 2020, and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines from existing wells.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended September 30,							Nine months ended September 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	8,385		$	8,865		(5%)	$	26,885		$	23,951		12%
Total revenues		8,385			8,865		(5%)		26,885			23,951		12%
Costs and expenses:
Operation and maintenance		877			911		(4%)		2,575			2,998		(14%)
General and administrative		50			85		(41%)		222			242		(8%)
Depreciation and amortization		1,918			1,913		0%		5,765			5,744		0%
Gain on asset sales, net		(9	)		—		*		(35	)		—		*
Total costs and expenses		2,836			2,909		(3%)		8,527			8,984		(5%)
Add:
Depreciation and amortization		1,918			1,913				5,765			5,744
Adjustments related to capital reimbursement activity		(5	)		(5	)			(14	)		(14	)
Gain on asset sales, net		(9	)		—				(35	)		—
Segment adjusted EBITDA	$	7,453		$	7,864		(5%)	$	24,074		$	20,697		16%

________

* Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $0.4 million compared to the three months ended September 30, 2019.

Nine months ended September 30, 2020. Segment adjusted EBITDA increased $3.4 million compared to the nine months ended September 30, 2019 primarily due to the increase in volume throughput previously discussed.

Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method and 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,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		512		777	(34%)		554		734	(25%)

Volume throughput for the Ohio Gathering system decreased compared to the three and nine months ended September 30, 2019 as a result of natural production declines on existing wells on the system and temporary production curtailments beginning in the second quarter of 2020, partially offset by the completion of new wells throughout 2019.

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,
	2020		2019		Percentage Change	2020		2019		Percentage Change
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	7,129	$	10,435	(32%)	$	22,582	$	29,584	(24%)
Segment adjusted EBITDA	$	7,129	$	10,435	(32%)	$	22,582	$	29,584	(24%)

Segment adjusted EBITDA for equity method investees decreased $3.3 million and $7.0 million compared to the three and nine months ended September 30, 2019 primarily as a result of the lower volume throughput described above.

Williston Basin. The Polar and Divide, Bison Midstream, Meadowlark Midstream and Tioga Midstream (through March 22, 2019; refer to Note 15 – Dispositions and Restructuring for details on the sale of Tioga 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,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)		14		9	56%		14		12	17%

Aggregate average daily throughput - liquids (Mbbl/d)		69		105	(34%)		81		101	(20%)

Natural gas. Natural gas volume throughput increased compared to the three and nine months ended September 30, 2019, primarily reflecting the completion of new wells behind the Bison Midstream system in the fourth quarter of 2019 and 2020 partially offset by natural production declines and the sale of Tioga Midstream.

Liquids. The decrease in liquids volume throughput compared to the three and nine months ended September 30, 2019, primarily associated with natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by the completion of new wells throughout 2019 and 2020.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended September 30,							Nine months ended September 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	10,941		$	16,685		(34%)	$	47,145		$	58,076		(19%)
Natural gas, NGLs and condensate sales		4,957			1,878		164%		12,412			11,231		11%
Other revenues		3,137			2,555		23%		9,055			8,133		11%
Total revenues		19,035			21,118		(10%)		68,612			77,440		(11%)
Costs and expenses:
Cost of natural gas and NGLs		2,968			(93	)	(3291%)		5,572			3,668		52%
Operation and maintenance		5,658			8,578		(34%)		18,207			20,800		(12%)
General and administrative		351			405		(13%)		1,381			1,117		24%
Depreciation and amortization		6,481			4,788		35%		19,463			14,958		30%
(Gain) loss on asset sales, net		(12	)		1		*		(50	)		(1,142	)	*
Long-lived asset impairment		—			—		*		—			18		*
Total costs and expenses		15,446			13,679		13%		44,573			39,419		13%
Add:
Depreciation and amortization		6,481			4,788				19,463			14,958
Adjustments related to MVC shortfall payments		2,125			2,081				(1,416	)		(1,387	)
Adjustments related to capital reimbursement activity		(470	)		(469	)			(1,404	)		(1,244	)
(Gain) loss on asset sales, net		(12	)		1				(50	)		(1,142	)
Long-lived asset impairment		—			—				—			18
Segment adjusted EBITDA	$	11,713		$	13,840		(15%)	$	40,632		$	49,224		(17%)

_______

* Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $2.1 million compared to the three months ended September 30, 2019 primarily due to lower liquids volume throughput on our systems as previously discussed.

Nine months ended September 30, 2020. Segment adjusted EBITDA decreased $8.6 million compared to the nine months ended September 30, 2019 primarily reflecting:

•

a decrease of $0.9 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the nine months ended September 30, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower liquids volume throughput on our systems as previously discussed.

Other items to note:

•

On March 22, 2019, we sold the Tioga Midstream system and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the then carrying value for Tioga Midstream at closing. The financial results of Tioga Midstream are included in our unaudited condensed consolidated financial statements for the period from January 1, 2019 through March 22, 2019.

DJ Basin. The Niobrara G&P systems provide midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows.

	DJ Basin
	Three months ended September 30,					Nine months ended September 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		27		33	(18%)		26		25	4%

Volume throughput increased compared to the nine months ended September 30, 2019, primarily as a result of ongoing drilling and completion activity across our service area and a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

Financial data for our DJ Basin reportable segment follows.

	DJ Basin
	Three months ended September 30,					Nine months ended September 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,051	$	7,039	(14%)	$	18,134	$	14,784	23%
Natural gas, NGLs and condensate sales		17		93	(82%)		158		279	(43%)
Other revenues		826		735	12%		2,853		2,776	3%
Total revenues		6,894		7,867	(12%)		21,145		17,839	19%
Costs and expenses:
Cost of natural gas and NGLs		46		11	*		57		21	*
Operation and maintenance		2,352		1,781	32%		7,222		5,658	28%
General and administrative		245		54	354%		468		186	152%
Depreciation and amortization		1,558		775	101%		4,587		2,038	125%
Loss on asset sales, net		—		—	*		20		—	*
Long-lived asset impairment		—		—	*		3,692		34,759	*
Total costs and expenses		4,201		2,621	60%		16,046		42,662	(62%)
Add:
Depreciation and amortization		1,558		775			4,587		2,038
Adjustments related to capital reimbursement activity		515		533			1,618		69
Loss on asset sales, net		—		—			20		—
Long-lived asset impairment		—		—			3,692		34,759
Segment adjusted EBITDA	$	4,766	$	6,554	(27%)	$	15,016	$	12,043	25%

* Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $1.8 million compared to the three months ended September 30, 2019, primarily reflecting:

•

a $1.0 million decrease in gathering services and related fees primarily due to natural production declines and limited drilling and completion activity associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

Nine months ended September 30, 2020. Segment adjusted EBITDA increased $3.0 million compared to the nine months ended September 30, 2019, primarily reflecting:

•

a $3.4 million increase in gathering services and related fees primarily due to the increase in volume throughput discussed above.

Other items to note:

•

During the nine months ended September 30, 2020 and 2019, we impaired certain long-lived assets in the DJ Basin (see Note 4 – Property, Plant and Equipment, Net). The impairment had no impact on segment adjusted EBITDA for the nine months ended September 30, 2020 and 2019.

Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows.

	Permian Basin
	Three months ended September 30,					Nine months ended September 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		34		20	70%		33		17	94%

Volume throughput increased compared to the three months ended September 30, 2019, primarily as a result of an uptick in customer volumes, partially offset by natural production declines from wells previously put in service.

Financial data for our Permian Basin reportable segment follows.

	Permian Basin
	Three months ended September 30,					Nine months ended September 30,
	2020		2019		Percentage Change	2020		2019			Percentage Change
	(In thousands)
Revenues:
Gathering services and related fees	$	2,595	$	986	163%	$	7,617	$	1,938		293%
Natural gas, NGLs and condensate sales		4,803		3,797	26%		13,537		10,424		30%
Other revenues		168		102	65%		481		183		163%
Total revenues		7,566		4,885	55%		21,635		12,545		72%
Costs and expenses:
Cost of natural gas and NGLs		4,958		3,242	53%		12,798		9,369		37%
Operation and maintenance		1,658		1,338	24%		4,301		3,962		9%
General and administrative		57		95	(40%)		234		210		11%
Depreciation and amortization		1,370		1,312	4%		4,102		3,547		16%
(Gain) loss on asset sales, net		14		—	*		1		(120	)	*
Long-lived asset impairment		—		—	*		182		8		*
Total costs and expenses		8,057		5,987	35%		21,618		16,976		27%
Add:
Depreciation and amortization		1,370		1,312			4,102		3,547
(Gain) loss on asset sales, net		14		—			1		(120	)
Long-lived asset impairment		—		—			182		8
Segment adjusted EBITDA	$	893	$	210	*	$	4,302	$	(996	)	*

________

*Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA increased $0.7 million compared to the three months ended September 30, 2019.

Nine months ended September 30, 2020. Segment adjusted EBITDA increased $5.3 million compared to the nine months ended September 30, 2019, primarily reflecting a $5.7 million increase in gathering services and related fees as a result of volume growth from ongoing drilling and completion activity and a more favorable volume and gathering rate mix from customers.

Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows.

	Piceance Basin
	Three months ended September 30,					Nine months ended September 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Aggregate average daily throughput (MMcf/d)		361		446	(19%)		370		464	(20%)

Volume throughput decreased compared to the three and nine months ended September 30, 2019, as a result of a natural production declines.

Financial data for our Piceance Basin reportable segment follows.

	Piceance Basin
	Three months ended September 30,							Nine months ended September 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	26,576		$	30,120		(12%)	$	79,987		$	92,515		(14%)
Natural gas, NGLs and condensate sales		528			1,733		(70%)		1,932			6,139		(69%)
Other revenues		1,233			1,258		(2%)		3,394			3,341		2%
Total revenues		28,337			33,111		(14%)		85,313			101,995		(16%)
Costs and expenses:
Cost of natural gas and NGLs		399			1,502		(73%)		1,176			4,255		(72%)
Operation and maintenance		6,073			7,273		(16%)		16,278			21,680		(25%)
General and administrative		196			128		53%		757			724		5%
Depreciation and amortization		11,305			11,798		(4%)		33,909			35,399		(4%)
(Gain) loss on asset sales, net		(94	)		—		*		(190	)		3		*
Total costs and expenses		17,879			20,701		(14%)		51,930			62,061		(16%)
Add:
Depreciation and amortization		11,305			11,798				33,909			35,399
Adjustments related to MVC shortfall payments		167			—				557			(103	)
Adjustments related to capital reimbursement activity		(333	)		(164	)			(865	)		(606	)
(Gain) loss on asset sales, net		(94	)		—				(190	)		3
Segment adjusted EBITDA	$	21,503		$	24,044		(11%)	$	66,794		$	74,627		(10%)

________

*Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $2.5 million compared to the three months ended September 30, 2019, primarily reflecting:

•

a $3.5 million decrease in gathering services and related fees as a result of natural production declines.

•

a $1.2 million decrease in operation and maintenance expense primarily due to $0.8 million in lower compensation expense associated with lower headcount from our cost cutting initiatives.

Other items to note:

•

In December 2019, we sold certain assets from our Red Rock Gathering system for approximately $12 million. The financial contribution of these assets are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

Nine months ended September 30, 2020. Segment adjusted EBITDA decreased $7.8 million compared to the nine months ended September 30, 2019, primarily reflecting:

•

a $12.5 million decrease in gathering services and related fees as a result of natural production declines.

•

a $5.4 million decrease in operation and maintenance expense primarily due to $3.0 million in lower compensation expense associated with lower headcount from our cost cutting initiatives and a $1.3 million decrease in property taxes.

Other items to note:

•

In December 2019, we sold certain assets from our Red Rock Gathering system for $12 million. The financial contribution of these assets are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

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,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		208		247	(16%)		215		255	(16%)

Volume throughput decreased compared to the three and nine months ended September 30, 2019 reflecting natural production declines, partially offset by new volumes from well completion activity through the third quarter of 2019.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended September 30,							Nine months ended September 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	10,545		$	11,286		(7%)	$	30,865		$	35,739		(14%)
Natural gas, NGLs and condensate sales		477			4,828		(90%)		7,206			11,705		(38%)
Other revenues (1)		1,399			1,706		(18%)		4,437			5,008		(11%)
Total revenues		12,421			17,820		(30%)		42,508			52,452		(19%)
Costs and expenses:
Cost of natural gas and NGLs		261			2,810		(91%)		3,342			7,384		(55%)
Operation and maintenance		4,810			5,567		(14%)		14,069			16,181		(13%)
General and administrative		351			201		75%		1,242			667		86%
Depreciation and amortization		3,795			3,810		(0%)		11,380			11,555		(2%)
(Gain) loss on asset sales, net		—			(350	)	*		17			(343	)	*
Long-lived asset impairment		—			—		*		4			10,236		*
Total costs and expenses		9,217			12,038		(23%)		30,054			45,680		(34%)
Add:
Depreciation and amortization		4,030			4,045				12,085			12,542
Adjustments related to MVC shortfall payments		—			1,453				—			4,358
Adjustments related to capital reimbursement activity		(29	)		(29	)			(85	)		(82	)
(Gain) loss on asset sales, net		—			(350	)			17			(343	)
Long-lived asset impairment		—			—				4			10,236
Segment adjusted EBITDA	$	7,205		$	10,901		(34%)	$	24,475		$	33,483		(27%)

________

*Not considered meaningful

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

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $3.7 million compared to the three months ended September 30, 2019 primarily reflecting:

•

a $1.5 million decrease in adjustments related to MVC shortfall payments attributable to an MVC that expired in 2019, and a $2.9 million decrease in total revenues, less cost of natural gas and NGLs which primarily reflects lower volume throughput.

Other items to note:

•

Also impacting total revenues and cost of natural gas and NGLs for the three months ended September 30, 2020, was the presentation of certain gathering services as a reduction to cost of natural gas and NGLs and the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019.

Nine months ended September 30, 2020. Segment adjusted EBITDA decreased $9.0 million compared to the nine months ended September 30, 2019 primarily reflecting:

•

a $4.4 million decrease in adjustments related to MVC shortfall payments attributable to an MVC that expired in 2019 and a $5.9 million decrease in total revenues less cost of natural gas and NGLs which primarily reflects lower volume throughput.

•

a $2.1 million decrease in various operation and maintenance expenses.

Other items to note:

•

In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 4 – Property, Plant and Equipment, Net). The noncash impairment expense had no impact on segment adjusted EBITDA for the nine months ended September 30, 2019.

•

Also impacting total revenues and cost of natural gas and NGLs for the nine months ended September 30, 2020, was the presentation of certain gathering services as a reduction to cost of natural gas and NGLs and the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019.

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,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		396		349	13%		366		358	2%

Volume throughput increased compared to the three and nine months ended September 30, 2019 primarily due to additional drilling and completion activities, partially offset by natural production declines.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended September 30,							Nine months ended September 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,871		$	5,987		15%	$	19,034		$	18,081		5%
Total revenues		6,871			5,987		15%		19,034			18,081		5%
Costs and expenses:
Operation and maintenance		771			783		(2%)		2,517			2,892		(13%)
General and administrative		69			237		(71%)		259			426		(39%)
Depreciation and amortization		2,298			2,286		1%		6,898			6,855		1%
Gain on asset sales, net		(8	)		—		*		(8	)		—		*
Goodwill impairment		—			16,211		*		—			16,211		*
Total costs and expenses		3,130			19,517		(84%)		9,666			26,384		(63%)
Add:
Depreciation and amortization		2,298			2,286				6,898			6,855
Goodwill impairment		—			16,211				—			16,211
Adjustments related to capital reimbursement activity		(9	)		(9	)			(28	)		(28	)
Gain on asset sales, net		(8	)		—				(8	)		—
Segment adjusted EBITDA	$	6,022		$	4,958		21%	$	16,230		$	14,735		10%

________

*Not considered meaningful

Three and nine months ended September 30, 2020. Segment adjusted EBITDA increased $1.1 million and $1.5

million compared to the three and nine months ended September 30, 2019.

Corporate and Other Overview for the Three and Nine Months Ended September 30, 2020 and 2019

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, construction management fees related to the Double E Project, transaction costs and interest expense.

	Corporate and Other
	Three months ended September 30,						Nine months ended September 30,
	2020			2019		Percentage Change	2020			2019		Percentage Change
	(Dollars in thousands)
Revenues:
Total revenues	$	644			534	21%	$	1,931		$	26,978	(93%)
Costs and expenses:
Cost of natural gas and NGLs		—			—	*		—			26,105	*
General and administrative		9,241			8,822	5%		35,344			35,404	(0%)
Transaction costs		726			129	463%		1,944			2,562	(24%)
Interest expense		19,018			23,462	(19%)		64,836			68,547	(5%)
Gain on early extinguishment of debt		(24,690	)		—	*		(78,925	)		—	*

________

* Not considered meaningful

Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of $25.0 million compared to nine months ended September 30, 2019, was attributable to lower natural gas, NGL and crude oil marketing activity.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of $26.1 million compared to nine months ended September 30, 2019, was attributable to lower marketing activity.

General and Administrative. General and administrative expense increased $0.4 million, compared to the three months ended September 30, 2019 and remained flat compared to the three and nine months ended September 30, 2019.

Transaction costs. The increase in transaction costs recognized during the three months ended September 30, 2020 compared to the three months ended September 30, 2019 was primarily due to costs associated with the GP Buy-In Transaction.

The decrease in transaction costs recognized during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was due to financial advisory costs incurred in 2019.

Interest Expense. Interest expense decreased $4.4 million and $3.7 million, respectively, compared to the three and nine months ended September 30, 2019, primarily due to our liability management initiatives which included our Open Market Repurchases and Tender Offer Repurchases, partially offset by a higher outstanding balance on the Revolving Credit Facility.

Summarized Financial Information

On March 2, 2020, the SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities (“Release 33-10762”), that amends the disclosure requirements related to certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate.

Under Release 33-10762, an SEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the parent company and its security is either (a) co-issued jointly and severally with the parent company’s security or (b) the subsidiary issuer’s security is fully and

unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees.

The rules become effective January 4, 2021, with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 8 - Debt). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762 as of and for the nine months ended September 30, 2020.

The supplemental summarized financial information below reflects SMLP's separate accounts, the combined accounts of Summit Holdings and its 100% owned finance subsidiary, Finance Corp (the “Co-Issuers”) and the Guarantor Subsidiaries (the Co-Issuers and, together with the Guarantor Subsidiaries, the “Obligor Group”) for the dates and periods indicated. The financial information of the Obligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between the Co-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes.

Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries and Permian Holdco and Summit Permian Transmission, who are unrestricted subsidiaries of SMLP and are not issuers or guarantors of the Senior Notes. The assets of our unrestricted subsidiaries are not available to satisfy the demands of the holders of the Senior Notes. In addition, our unrestricted subsidiaries are subject to certain contractual restrictions related to the payment of dividends, and other rights in favor of their non-affiliated stakeholders, that limit their ability to satisfy the demands of the holders of the Senior Notes.

A list of each of SMLP’s subsidiaries that is a guarantor, issuer or co-issuer of our registered securities subject to the reporting requirements in Release 33-10762 is filed as Exhibit 22.1 to this Quarterly Report on Form 10-Q.

Summarized Balance Sheet Information. Summarized balance sheet information as of September 30, 2020 and December 31, 2019 follow.

	September 30, 2020
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	5,719	$	124,603
Noncurrent assets		7,886		2,308,461

Liabilities
Current liabilities	$	10,173	$	60,721
Noncurrent liabilities		2,931		1,438,929

	December 31, 2019
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	7,396	$	104,964
Noncurrent assets		9,835		2,389,032

Liabilities
Current liabilities	$	14,527	$	69,177
Noncurrent liabilities		163,163		1,514,250

Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities' results would have been had they operated on a stand-alone basis. Summarized statements of operations for the nine months ended September 30, 2020 and for the year ended December 31, 2019 follow.

	Nine months ended September 30, 2020
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	287,063
Total costs and expenses		5,289			216,715
(Loss) income before income taxes and income from equity method investees		(5,120	)		95,818
Income from equity method investees		—			8,498
Net (loss) income	$	(6,612	)	$	104,316

	Year ended December 31, 2019
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	443,528
Total costs and expenses		8,719			397,939
Loss before income taxes and loss from equity method investees		(25,805	)		(28,840	)
Loss from equity method investees (1)		—			(336,950	)
Net loss	$	(27,036	)	$	(365,790	)

(1)	Amount includes a $329.7 million impairment of our equity method investment in Ohio Gathering and a $6.3 million impairment of long-lived assets in OCC.

Liquidity and Capital Resources

Distribution Suspension. On May 3, 2020, we suspended distributions to holders of our common units and suspended payments of distributions to holders of our Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020, to enable us to retain an incremental approximately $76 million of cash in the business annually, which we plan to use to de-lever the balance sheet, enhance liquidity and increase financial flexibility. The unpaid distributions on the Series A Preferred Units will continue to accrue. We expect to fund future capital expenditures with cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt and equity securities and proceeds from potential asset divestitures. As of October 31, 2020, the amount of accrued and unpaid distributions on the Series A Preferred Units was $19.7million.

Exchange Offer. On June 18, 2020, the Partnership commenced the Exchange Offer. The Exchange Offer expired on July 28, 2020 and resulted in the Partnership exchanging 62,816 Series A Preferred Units for a total of 12,267,670 common units, net of units withheld for tax withholdings. Upon completion of the Exchange Offer, the Partnership has 237,184 Series A Preferred Units outstanding and holders of Series A Preferred Units who did not tender into the Exchange Offer retained their Series A Preferred Units with all the preferences and rights thereunder.

Term Loan Restructuring. On September 29, 2020, SMP Holdings and the Partnership entered into the TSA with an ad hoc group of the Term Loan Lenders that will result in the TL Restructuring, which includes (i) the Partnership’s cash payment of $26.5 million to the Term Loan Lenders, (ii) the execution of a strict foreclosure by the collateral agent under the SMPH Term Loan for the benefit of the Term Loan Lenders on the 34.6 million common units pledged as collateral to the SMPH Term Loan, and (iii) the payment of certain fees and expenses by the Partnership. At the closing of the TL Restructuring, which is expected to occur during the quarterly period ended December 31, 2020, the SMPH Term Loan will be fully satisfied and cease to exist. Upon closing of the TL Restructuring we will recognize a gain equal to the difference between the face value of the cancelled debt and the fair value of the total consideration transferred, including unamortized debt issuance costs, and certain direct transaction costs related to the restructuring. At September 30, 2020, the Partnership classified the SMPH Term Loan as current.

Indebtedness Compliance. We are currently in compliance with all covenants contained in our Revolving Credit Facility and Senior Notes at September 30, 2020. The Partnership’s total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) were 4.9 to 1.0 and 2.7 to 1.0, respectively, relative to maximum threshold limits of 5.50 to 1.0 and 3.75 to 1.0. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on our ability to access the capital markets at a competitive cost to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows.

COVID-19 Impact. We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our liquidity and capital resources. Considering the current commodity price backdrop and COVID-19 pandemic, we have collaborated extensively with our customer base over the past several months. Given continued volatility in market conditions since March 2020 and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. For example, beginning in June 2020, in the Utica Shale, a customer curtailed in excess of 150 MMcf/d of production which impacted volume throughput across our gathering system and the financial results of that segment through the middle of the third quarter of 2020, when more favorable natural gas prices returned and that customer reversed that particular production curtailment. We also recently amended gathering contracts with two key Williston Basin customers to extend the terms of the gathering agreement acreage dedications, in exchange for a modest gathering fee concession. We expect 2020 total capital expenditures to range from $55 million to $65 million.

As we cannot predict the duration or scope of the COVID-19 pandemic and its impact on our customers and suppliers, the potential negative financial impact to our results cannot be reasonably estimated but could be material. We are actively managing the business to maintain cash flow and we have sufficient available liquidity. We believe that these factors will allow us to meet our anticipated funding requirements.

Capital Markets Activity

We had no capital markets activity resulting in new capital issuances during the nine months ended September 30, 2020. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2019 Annual Report.

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility that matures in May 2022. As of September 30, 2020, the outstanding balance of the Revolving Credit Facility was $808.5 million and the unused portion totaled $437.4 million, after giving effect to the issuance thereunder of a $4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of September 30, 2020 was approximately $191 million. There were no defaults or events of default during the nine months ended September 30, 2020, and, as of September 30, 2020, we were in compliance with the financial covenants in the Revolving Credit Facility.

Open Market Repurchases of Senior Notes. During the nine months ended September 30, 2020, the Partnership made Open Market Repurchases that resulted in the extinguishment of $32.4 million face value of the outstanding 2022 Senior Notes and $106.2 million face value of the 2025 Senior Notes. Total cash consideration paid to complete the Open Market Repurchases totaled $82.9 million and the Partnership recognized a $56.2 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

Tender Offers. In September 2020, the Co-Issuers completed the Tender Offers to purchase a portion of the 2022 and 2025 Senior Notes. Upon concluding the Tender Offers, the Partnership repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to complete the Tender Offers totaled $48.7 million and the Partnership recognized a $23.3 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

ECP Loans. On August 7, 2020, we repaid all amounts outstanding under the ECP Loans which included $35 million of principal and $0.6 million of accrued interest. The ECP Loan repayment was financed in full with borrowings under our Revolving Credit Facility. We repaid the ECP Loans in order to eliminate certain restrictive covenants associated with the credit agreement and to take advantage of more favorable terms under the Revolving Credit Facility.

For additional information on our long-term debt, see Note 8 – Debt.

LIBOR Transition

LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate (“SOFR”), calculated using short-term repurchase agreements backed by Treasury securities. We are evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations.

We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. The potential effect of any such event on interest expense cannot yet be determined.

Cash Flows

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

	Nine months ended September 30,
	2020			2019
	(In thousands)
Net cash provided by operating activities	$	146,758		$	127,617
Net cash used in investing activities		(124,898	)		(65,287	)
Net cash provided by (used in) financing activities		(8,486	)		(68,277	)
Net change in cash, cash equivalents and restricted cash	$	13,374		$	(5,947	)

Operating activities. Cash flows from operating activities for the nine months ended September 30, 2020 primarily reflected:

•

a $12.5 million increase in accounts receivable related to the timing of invoicing and cash collections;

•

a $5.5 million increase in deferred revenue for cash receipts not yet recognized as revenue;

•

a $10.8 million decrease in accrued expenses primarily due to the timing of accrued payment obligations; and

•

other changes in working capital.

Investing activities. Cash flows used in investing activities during the nine months ended September 30, 2020 primarily reflected:

•

$92.1 million for investments in the Double E joint venture relating to the Double E Project; and

•

$35.3 million of capital expenditures primarily attributable to the DJ Basin of $11.3 million, the Williston Basin of $8.4 million and Summit Permian of $6.3 million.

Cash flows used in investing activities during the nine months ended September 30, 2019 primarily reflected:

•

$151.7 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $66.8 million, Summit Permian of $43.4 million, the Williston Basin of $20.3 million and Corporate and Other, which includes $15.4 million of capital expenditures relating to the Double E Project;

•

$89.5 million of net proceeds from the Tioga Midstream sale;

•

$7.3 million for a distribution from an equity method investment; and

•

$11.3 million for an investment in an equity method investee.

Financing activities. Cash flows used in financing activities during the nine months ended September 30, 2020 primarily reflected:

•

$165.5 million of borrowings under our Revolving Credit Facility;

•

$48.7 million of net proceeds from the issuance of Subsidiary Series A Preferred Units;

•

$35.0 million of net borrowings under ECP Loans;

•

$82.8 million for Open Market Repurchases;

•

$48.7 million for Tender Offers;

•

$41.8 million to purchase common units in the GP Buy-In Transaction;

•

$35.0 million for the repayment of ECP Loans;

•

$34.0 million for repayments under our Revolving Credit Facility;

•

$6.3 million for repayments on the SMPH Term Loan; and

•

$6.0 million of distributions to noncontrolling interest SMLP unitholders.

Cash flows used in financing activities during the nine months ended September 30, 2019 primarily reflected:

•

$149.7 million of distributions; and

•

$126.0 million of borrowings under our Revolving Credit Facility; and

•

$131.0 million for repayments under our Revolving Credit Facility.

Contractual Obligations Update

Double E Project

We are leading the development, permitting and construction of the Double E Project and will operate the pipeline upon its commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $300 million. Assuming timely receipt of the required regulatory approvals and no material delays in construction, we expect that the Double E Project will be placed into service in the fourth quarter of 2021.

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, 2020, cash paid for capital expenditures totaled $35.3 million and included $11.0 million of maintenance capital expenditures. For the nine months ended September 30, 2020, there were no contributions to Ohio Gathering and we contributed $92.1 million to Double E (see Note 6 – Equity Method Investments).

We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our business for the foreseeable future without adversely impacting our liquidity.

Considering the current commodity price backdrop and COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest in Double E, which we intend to be credit positive to SMLP. We are currently targeting a financing structure that limits additional cash investments made by SMLP beyond 2020, and which shifts a substantial majority of our Double E capital commitments to third parties.

There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.

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.

Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a potential customer, 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.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the nine months ended September 30, 2020.

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, 2019.

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 officers and employees 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 or our subsidiaries 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:

•

our decision whether to pay, or our ability to grow, our cash distributions;

•

fluctuations in natural gas, NGLs and crude oil prices, including as of a result of political or economic measures taken by various countries or OPEC;

•

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

•

the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows;

•

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 divest of certain of our assets or joint ventures to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets;

•

the effectiveness of the Reverse Unit Split for regaining and maintaining compliance with the continued listing standards of the NYSE;

•

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 and preferred equity 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, compression, 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, compression, 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;

•

our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results;

•

the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation;

•

the ability to meet obligations under the SMPH Term Loan;

•

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, 2020, we had approximately $589.1 million principal of fixed-rate Senior Notes, $808.5 million outstanding under our variable rate Revolving Credit Facility and $155.2 million principal of variable rate debt on the SMPH Term Loan (see Note 8 - Debt). 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, 2019. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2019 Annual Report.

Commodity Price Risk

We currently generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, some of which include MVCs and most of which include areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. Our gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. Our gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, like the Henry Hub Index, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. Our current commodity price risk exposure has not changed materially since December 31, 2019. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2019 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, 2020 and (ii) no change in internal control over financial reporting occurred during the quarter ended September 30, 2020, 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 14 – Commitments and Contingencies and in the 2019 Annual Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of the 2019 Annual Report, the Item 1A. Risk Factors of our quarterly report on Form 10-Q for the three months ended March 31, 2020, as filed with the SEC on May 8, 2020, and the Item 1A. Risk Factors of our quarterly report on Form 10-Q for the three months ended June 30, 2020, as filed with the SEC on August 7, 2020 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.

Risks Relating to COVID-19

The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows.

The ongoing coronavirus (COVID-19) outbreak continues to be a rapidly evolving situation. As of November 3, 2020, the CDC had recorded over 9.2 million cases in the United States and over 230,000 deaths, and the pandemic has resulted in a massive increase in the U.S. unemployment rate. The pandemic has resulted in widespread adverse impacts on the global economy and on our business, including our customers, employees, supply chain, and distribution network. We are currently unable to predict the ultimate impact that it may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

In the midst of the ongoing COVID-19 pandemic, oil prices declined significantly due to potential increases in supply emanating from a disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. For example, we have experienced a $5.2 million decrease in gathering services and related fees in the Williston Basin primarily due to lower liquids throughput associated in part with a decrease in demand resulting from the COVID-19 pandemic. These industry conditions, coupled with those resulting

from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, extend cuts again in June and cut its long-term forecast for oil demand growth in October, there is no assurance that the agreement will continue to be observed by its members, and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. After increasing supply through the summer of 2020, certain OPEC members recently announced price cuts for October, potentially signaling continued pressure on demand. Such responses could cause our pipelines and storage tanks to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows. At this point, we cannot accurately predict what effects current market conditions due to the COVID-19 pandemic and failed OPEC negotiations will have on our business, which will depend on, among other factors, the ultimate geographic spread of the virus, the duration of the outbreak and the extent and overall economic effects of the governmental response to the pandemic.

The impact of COVID-19 and the OPEC price war may also exacerbate other risks discussed in Item 1A of the 2019 Annual Report, any of which could have a material effect on us. This situation is changing rapidly, and additional impacts may arise that we are not aware of currently.

Risks Related to Our Business

If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common units, which would have an adverse impact on the trading volume, liquidity and market price of our common units.

We received a formal notice from the NYSE on April 10, 2020 indicating noncompliance with the continued listing standard set forth in Rule 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had fallen below $1.00 per unit over a period of 30 consecutive trading days, which is the minimum average unit price for continued listing on the NYSE. We have until December 19, 2020 to regain compliance with the minimum unit price requirement, with the possibility of extension at the discretion of the NYSE. In order to regain compliance, on the last trading day in any calendar month during the cure period, the common units must have: (i) a closing price of at least $1.00 per unit and (ii) an average closing price of at least $1.00 per unit over the 30 trading day period ending on the last trading day of such month. On October 15, 2020 the Board approved a 1-for-15 reverse split of the Partnership’s common units, effective as of 6:01 p.m., New York City time, on November 9, 2020 in order to, among other things, increase the per-unit trading price of the Partnership’s common units to satisfy the $1.00 minimum bid price requirement for continued listing on the NYSE.

If we fail to regain compliance with Section 802.01C of the NYSE Listed Company Manual by the end of the cure period, the common units will be subject to the NYSE’s suspension and delisting procedures. If the common units ultimately were to be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price of the common units, reduce the number of investors willing to hold or acquire the common units and negatively impact our ability to access equity markets and obtain financing.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

The Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accumulate and are cumulative at the rate of 9.50% per annum of $1,000, the liquidation preference of the Series A Preferred Units and (ii) on and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%. On May 3, 2020, we announced the suspension of distributions payable on both our common units and our Series A Preferred Units. We did not make a distribution on our common units with respect to the first quarter of 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020. As of October 30, 2020, the amount of accrued and

unpaid distributions on the Series A Preferred Units was $19.7 million. Unpaid distributions on the Series A Preferred Units will continue to accrue.

In addition, our Subsidiary Series A Preferred Units issued by Permian Holdco have priority over the common unitholders with respect to the cash flow from Permian Holdco. The distribution rate of the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 issue amount per outstanding Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service.

Our obligation to pay distributions on our Series A Preferred Units and Permian Holdco’s obligation to pay the distributions on the Subsidiary Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of the Series A Preferred Units and Permian Holdco’s obligations to the holders of the Subsidiary Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to an organization that is exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year the exempt organization is allocated the income. Under the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.

Under the Tax Reform Legislation, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit number		Description
3.1		Fourth Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.1 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
3.2		Second Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed June 2, 2020 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1		Amendment to Warrants to Purchase Common Units, dated August 7, 2020, by and among Summit Midstream Partners, LP, SMP TopCo, LLC and SMLP Holdings, LLC (Incorporated herein by reference to Exhibit 10.11 to SMLP’s Quarterly Report on Form 10-Q dated August 7, 2020 (Commission File No. 001-34666))
10.2	***	Transaction Support Agreement, dated September 29, 2020, by and among Summit Midstream Partners Holdings, LLC, Summit Midstream Partners, LLC, Summit Midstream Partners, LP and the Initial Directing Lenders listed therein (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated September 30, 2020 (Commission File No. 001-34666))
10.3	*	Separation and General Release Agreement, effective as of August 7, 2020, by and between Summit Midstream Partners, LP and Brock Degeyter
10.4	*	Employment Agreement, effective as of September 4, 2020, by and between Summit Midstream Partners, LP and James Johnston
22.1		Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities (Incorporated herein by reference to Exhibit 22.1 to SMLP's Report on Form 10-Q filed May 8, 2020 (Commission File No. 001-35666)
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Heath Deneke, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, 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 Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer
101.INS	**	Inline 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	**	Inline XBRL Taxonomy Extension Schema
101.CAL	**	Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	Inline XBRL Taxonomy Extension Label Linkbase
101.PRE	**	Inline XBRL Taxonomy Extension Presentation Linkbase
104	**	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith.

** 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.

*** Certain portions of this exhibit have been omitted pursuant to Item 601(b)(10) of Regulation S-K. The Partnership agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.

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 6, 2020	/s/ Marc D. Stratton

	Marc D. Stratton, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)