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

Three months ended March 31,

Percentage of total revenues (1):

Counterparty A - Piceance Basin

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 March 31, 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 Securities 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 April 30, 2020
Common Units		94,558,166 units

TABLE OF CONTENTS

COMMONLY USED OR DEFINED TERMS		2

PART I	FINANCIAL INFORMATION	5
Item 1.	Financial Statements.	5
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019	5
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2020 and 2019	6
	Unaudited Condensed Consolidated Statements of Partners' Capital for the three months ended March 31, 2020 and 2019	7
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2020 and 2019	8
	Notes to Unaudited Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	55
Item 4.	Controls and Procedures.	56

PART II	OTHER INFORMATION	57
Item 1.	Legal Proceedings.	57
Item 1A.	Risk Factors.	57
Item 6.	Exhibits.	60

SIGNATURES		61

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
5.5% Senior Notes	Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
5.75% Senior Notes	Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025
associated natural gas	a form of natural gas which is found with deposits of petroleum, either dissolved in the 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 referred to as 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; also known as the Sponsor
Epping	Epping Transmission Company, LLC
EPU	earnings or loss per unit
Equity Restructuring	a series of transactions consummated on March 22, 2019, pursuant to which the Partnership cancelled its IDRs and converted its 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings
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
GP interest	2.0% general partner interest of GP in the Partnership prior to the Equity Restructuring and a non-economic general partner interest after the Equity Restructuring
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
IDRs	incentive distribution rights
LIBOR	London Interbank Offered Rate
Mbbl	one thousand barrels
Mbbl/d	one thousand barrels per day
Mcf	one thousand cubic feet
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Meadowlark Midstream	Meadowlark Midstream Company, LLC

MMcf	one million cubic feet
MMcf/d	one million cubic feet per day
Mountaineer Midstream	Mountaineer Midstream 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
Remaining Consideration	the consideration to be paid to SMP Holdings in 2022 in connection with the 2016 Drop Down, the present value of which is reflected on our balance sheets as the Deferred Purchase Price Obligation
Revolving Credit Facility	the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 2017, 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) the change in the Deferred Purchase Price Obligation, (viii) impairments and (ix) other noncash expenses or losses, less other noncash income or gains
Senior Notes	The 5.5% Senior Notes and the 5.75% 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
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
Sponsor	Energy Capital Partners II, LLC and its parallel and co-investment funds; also known as Energy Capital Partners
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 Niobrara	Summit Midstream Niobrara, 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
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

	March 31,		December 31,
	2020		2019
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	67,694	$	4,948
Restricted cash		4,057		27,392
Accounts receivable		83,648		102,118
Other current assets		4,265		5,018
Total current assets		159,664		139,476
Property, plant and equipment, net		1,869,882		1,882,251
Intangible assets, net		224,076		232,278
Investment in equity method investees		363,578		309,728
Other noncurrent assets		7,735		9,718
Total assets	$	2,624,935	$	2,573,451

Liabilities and Capital
Current liabilities:
Trade accounts payable	$	22,294	$	24,415
Accrued expenses		11,413		11,482
Due to affiliate		776		311
Deferred revenue		14,318		13,493
Ad valorem taxes payable		3,696		8,477
Accrued interest		15,370		12,311
Accrued environmental remediation		2,016		1,725
Other current liabilities		8,621		11,933
Total current liabilities		78,504		84,147
Long-term debt		1,491,716		1,470,299
Deferred Purchase Price Obligation		180,750		178,453
Noncurrent deferred revenue		43,045		38,709
Noncurrent accrued environmental remediation		2,618		2,926
Other noncurrent liabilities		8,044		7,951
Total liabilities		1,804,677		1,782,485
Commitments and contingencies (Note 15)

Mezzanine Capital
Subsidiary Series A Preferred Units (66,002 units issued and outstanding at March 31, 2020 and 30,058 units issued and outstanding at December 31, 2019)		62,341		27,450

Partners' Capital
Series A Preferred Units (300,000 units issued and outstanding at March 31, 2020 and December 31, 2019)		300,741		293,616
Common limited partner capital (94,469,385 units issued and outstanding at March 31, 2020 and 93,493,473 units issued and outstanding at December 31, 2019)		457,176		469,900
Total partners' capital		757,917		763,516
Total liabilities, mezzanine capital and partners' capital	$	2,624,935	$	2,573,451

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 March 31,
	2020			2019
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	83,792		$	86,964
Natural gas, NGLs and condensate sales		13,780			37,928
Other revenues		7,331			6,516
Total revenues		104,903			131,408
Costs and expenses:
Cost of natural gas and NGLs		8,225			31,759
Operation and maintenance		21,811			24,222
General and administrative		16,378			17,281
Depreciation and amortization		29,629			27,727
Transaction costs		11			950
Loss (gain) on asset sales, net		115			(961	)
Long-lived asset impairment		3,821			44,951
Total costs and expenses		79,990			145,929
Other (expense) income		(428	)		209
Interest expense		(20,218	)		(17,527	)
Deferred Purchase Price Obligation		(2,297	)		(4,427	)
Income (loss) before income taxes and income (loss) from equity method investees		1,970			(36,266	)
Income tax benefit (expense)		28			(207	)
Income (loss) from equity method investees		3,311			(441	)
Net income (loss)	$	5,309		$	(36,914	)
Less:
Net income attributable to General Partner, including IDRs		—			12
Net income (loss) attributable to limited partners		5,309			(36,926	)
Net income attributable to Series A Preferred Units		7,125			7,125
Net income attributable to Subsidiary Series A Preferred Units		945			—
Net loss attributable to common limited partners	$	(2,761	)	$	(44,051	)

Loss per limited partner unit:
Common unit – basic	$	(0.03	)	$	(0.58	)
Common unit – diluted	$	(0.03	)	$	(0.58	)

Weighted-average limited partner units outstanding:
Common units – basic		93,675			75,793
Common units – diluted		93,675			75,793

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

	Partners' capital
	Limited partners
	Series A Preferred Units		Common			Total
	(In thousands)
Partners' capital, January 1, 2020	$	293,616	$	469,900		$	763,516
Net income (loss)		7,125		(2,761	)		4,364
Distributions to unitholders		—		(11,702	)		(11,702	)
Unit-based compensation		—		2,723			2,723
Tax withholdings and associated payments on vested SMLP LTIP awards		—		(984	)		(984	)
Partners' capital, March 31, 2020	$	300,741	$	457,176		$	757,917

	Partners' capital
	Limited partners
	Series A Preferred Units		Common			General Partner			Total
	(In thousands)
Partners' capital, January 1, 2019	$	293,616	$	902,358		$	25,250		$	1,221,224
Net income (loss)		7,125		(44,051	)		12			(36,914	)
Conversion of General Partner economic interests		—		22,222			(22,222	)		—
Distributions to unitholders		—		(42,241	)		(3,040	)		(45,281	)
Unit-based compensation		—		2,526			—			2,526
Tax withholdings and associated payments on vested SMLP LTIP awards		—		(2,522	)		—			(2,522	)
Partners' capital, March 31, 2019	$	300,741	$	838,292		$	—		$	1,139,033

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

	March 31,
	2020			2019
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	5,309		$	(36,914	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		29,863			28,116
Noncash lease expense		473			765
Amortization of debt issuance costs		1,109			1,080
Deferred Purchase Price Obligation		2,297			4,427
Unit-based and noncash compensation		2,723			2,526
(Income) loss from equity method investees		(3,311	)		441
Distributions from equity method investees		7,494			8,583
Loss (gain) on asset sales, net		115			(961	)
Long-lived asset impairment		3,821			44,951
Changes in operating assets and liabilities:
Accounts receivable		18,470			4,675
Trade accounts payable		3,960			271
Accrued expenses		(69	)		(1,199	)
Due from affiliate		465			80
Deferred revenue, net		5,161			2,323
Ad valorem taxes payable		(4,781	)		(6,184	)
Accrued interest		3,059			3,111
Accrued environmental remediation, net		(17	)		(548	)
Other, net		(2,173	)		(2,832	)
Net cash provided by operating activities		73,968			52,711
Cash flows from investing activities:
Capital expenditures		(18,583	)		(60,848	)
Proceeds from asset sale (net of cash of $1,475 for the period ended March 31, 2019)		—			89,461
Investment in equity method investee		(58,033	)		—
Other, net		217			(120	)
Net cash (used in) provided by investing activities		(76,399	)		28,493

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	March 31,
	2020			2019
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders		(11,702	)		(45,281	)
Borrowings under Revolving Credit Facility		55,000			69,000
Repayments under Revolving Credit Facility		(34,000	)		(101,000	)
Proceeds from issuance of Series A preferred units, net of costs		33,946			—
Other, net		(1,402	)		(2,968	)
Net cash provided by (used in) financing activities		41,842			(80,249	)
Net change in cash, cash equivalents and restricted cash		39,411			955
Cash, cash equivalents and restricted cash, beginning of period		32,340			4,345
Cash, cash equivalents and restricted cash, end of period (1)	$	71,751		$	5,300

Supplemental cash flow disclosures:
Cash interest paid	$	16,523		$	15,229
Less capitalized interest		491			1,915
Interest paid (net of capitalized interest)	$	16,032		$	13,314

Cash paid for taxes	$	—		$	—

Noncash investing and financing activities
Capital expenditures in trade accounts payable (period-end accruals)	$	13,765		$	23,389
Right-of-use assets relating to ASC Topic 842		—			5,448

(1) A reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets follow:
	March 31,
	2020			2019
	(In thousands)
Cash and cash equivalents	$	67,694		$	5,300
Restricted cash		4,057			—
Total cash, cash equivalents and restricted cash	$	71,751		$	5,300

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.

The General Partner, a Delaware limited liability company, manages our operations and activities. Summit Investments, a Delaware limited liability company, is the ultimate owner of our General Partner and has the right to appoint the entire Board of Directors. Summit Investments is controlled by Energy Capital Partners.

As of March 31, 2020, SMP Holdings, a wholly owned subsidiary of Summit Investments, beneficially owned 45,318,866 SMLP common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 SMLP common units.

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

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

•

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

•

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

•

Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming;

•

Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico;

•

Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas;

•

Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;

•

DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

•

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

Other than our investments in Double E and Ohio Gathering, all of our business activities are conducted through wholly owned operating subsidiaries.

Presentation and Consolidation. We prepare our unaudited condensed consolidated financial statements in accordance with GAAP as established by the FASB. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the disclosure of commitments and contingencies. Further, these estimates and other factors, including those outside of our control, such as the impact of lower commodity prices, may have a significant negative impact to our business, financial condition, results of operations and cash flows. Although management believes these estimates are reasonable, actual results could differ from its estimates.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the SEC. Certain information and note disclosures normally included in the annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments which are necessary to fairly present the unaudited condensed consolidated balance sheet as of March 31, 2020, the unaudited condensed consolidated statements of operations and statements of partners’ capital for the three months ended March 31, 2020 and 2019 and the unaudited condensed consolidated statements of cash flows for the three months ended March 31, 2020 and 2019. The balance sheet at December 31, 2019 included herein was derived from our audited financial statements, but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our annual report on Form 10-K for the year ended December 31, 2019, as filed with the SEC on March 9, 2020 (the "2019 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.

Risks and Uncertainties. We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it 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 quarter of 2020, only one month of the quarter was affected by COVID-19 and if the current conditions continue, subsequent quarters may reflect these conditions for a full quarter. We are unable to predict the ultimate impact that COVID-19 may have on our business, future results of operations, financial position or cash flows.

The full 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 new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. 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 SIGNIFICANT ACCOUNTING POLICIES

Except for the changes below, there have been no changes to our significant accounting policies since December 31, 2019.

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

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

•

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 our unaudited condensed consolidated financial statement 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 our unaudited condensed consolidated financial statements or disclosures.

Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncement as of March 31, 2020:

•

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. We are currently evaluating the provisions of ASU 2020-04 to determine its impact on our unaudited condensed consolidated financial statements and disclosures.

3. REVENUE

The majority of our revenue is derived from long-term, fee-based contracts with our customers, which include original terms of up to 25 years. We recognize revenue earned from fee-based gathering, compression, treating and processing services in Gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within Cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in Natural gas, NGLs and condensate sales; the associated expense is included in Operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues.

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

in-kind, we measure the transaction price at the point of sale when the volume, mix and market price of the commodities are known.

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

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

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

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

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

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

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

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

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

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

	2020		2021		2022		2023		2024		Thereafter
	(In thousands)
Gathering services and related fees	$	86,916	$	102,127	$	84,736	$	66,693	$	50,608	$	58,672

Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. Ohio Gathering is excluded from the tables below due to equity method accounting. For more detailed information about reportable segments, see Note 4.

	Reportable Segments
	Three months ended March 31, 2020
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments		Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	6,962	$	23,797	$	6,855	$	2,311	$	27,189	$	10,443	$	6,235	$	83,792	$	—	$	83,792
Natural gas, NGLs and condensate sales		—		4,324		70		4,512		1,003		3,871		—		13,780		—		13,780
Other revenues		—		3,142		1,034		187		1,065		1,260		—		6,688		643		7,331
Total	$	6,962	$	31,263	$	7,959	$	7,010	$	29,257	$	15,574	$	6,235	$	104,260	$	643	$	104,903

	Reportable Segments
	Three months ended March 31, 2019
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	7,495	$	25,706	$	3,724	$	366	$	31,840	$	13,025	$	6,197	$	88,353	$	(1,389	)	$	86,964
Natural gas, NGLs and condensate sales		—		5,585		85		4,221		2,302		604		—		12,797		25,131			37,928
Other revenues		—		2,908		1,007		32		1,138		1,656		—		6,741		(225	)		6,516
Total	$	7,495	$	34,199	$	4,816	$	4,619	$	35,280	$	15,285	$	6,197	$	107,891	$	23,517		$	131,408

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

	March 31, 2020			December 31, 2019
	(In thousands)
Contract assets, beginning of period	$	3,902		$	8,755
Additions		13,877			18,077
Transfers out		(425	)		(22,930	)
Contract assets, end of period	$	17,354		$	3,902

As of March 31, 2020, receivables with customers totaled $58.0 million and contract assets totaled $17.4 million which were included in the Accounts receivable caption on the unaudited condensed consolidated balance sheet.

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

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. We recognize contract liabilities under these arrangements in revenue over the contract period. For the three months ended March 31, 2020 and 2019, we recognized $2.4 million and $2.7 million of gathering services and related fees which were included in the contract liability balance as of the beginning of the period. See Note 8 for additional details.

4. SEGMENT INFORMATION

As of March 31, 2020, our reportable segments are:

•

the Utica Shale, which is served by Summit Utica;

•

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

•

the Williston Basin, which is served by Polar and Divide and Bison 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, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Until December 1, 2019, we owned certain assets in the Red Rock Gathering system operating in the Piceance Basin. Refer to Note 16 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream and on the sale of certain assets in the Red Rock Gathering system.

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

The Ohio Gathering reportable segment includes our investment in Ohio Gathering. Income or loss from equity method investees, as reflected on the unaudited condensed consolidated statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag (see Note 7).

For the three months ended March 31, 2020, other than the investment activity described in Note 7, 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 third 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 our 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.

	March 31, 2020		December 31, 2019
	(In thousands)
Assets (1):
Utica Shale	$	205,341	$	206,368
Ohio Gathering		271,268		275,000
Williston Basin		452,684		452,152
DJ Basin		200,473		205,308
Permian Basin		184,043		185,708
Piceance Basin		622,403		631,140
Barnett Shale		345,248		350,638
Marcellus Shale		184,279		184,631
Total reportable segment assets		2,465,739		2,490,945
Corporate and Other		159,196		82,506
Total assets	$	2,624,935	$	2,573,451

(1) At March 31, 2020, Corporate and Other included $92.3 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.

Revenues by reportable segment follow.

	Three months ended March 31,
	2020		2019
	(In thousands)
Revenues (1):
Utica Shale	$	6,962	$	7,495
Williston Basin		31,263		34,199
DJ Basin		7,959		4,816
Permian Basin		7,010		4,619
Piceance Basin		29,257		35,280
Barnett Shale		15,574		15,285
Marcellus Shale		6,235		6,197
Total reportable segments revenue		104,260		107,891
Corporate and Other		643		26,838
Eliminations		—		(3,321	)
Total revenues	$	104,903	$	131,408

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

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

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

* Less than 10%

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

	Three months ended March 31,
	2020		2019
	(In thousands)
Depreciation and amortization (1):
Utica Shale	$	1,927	$	1,908
Williston Basin		6,495		5,436
DJ Basin		1,527		799
Permian Basin		1,345		1,072
Piceance Basin		11,298		11,791
Barnett Shale (2)		4,032		4,330
Marcellus Shale		2,300		2,283
Total reportable segment depreciation and amortization		28,924		27,619
Corporate and Other		939		497
Total depreciation and amortization	$	29,863	$	28,116

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

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

Cash paid for capital expenditures by reportable segment follow.

	Three months ended March 31,
	2020		2019
	(In thousands)
Cash paid for capital expenditures (1):
Utica Shale	$	909	$	101
Williston Basin		4,943		8,023
DJ Basin		6,298		28,356
Permian Basin		3,281		7,057
Piceance Basin		346		1,226
Barnett Shale (2)		657		(118	)
Marcellus Shale		422		102
Total reportable segment capital expenditures		16,856		44,747
Corporate and Other		1,727		16,101
Total cash paid for capital expenditures	$	18,583	$	60,848

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

(2) For the three months ended March 31, 2019, the amount includes sales tax reimbursements of $1.1 million.

During the three months ended March 31, 2019, Corporate and Other included cash paid of $0.3 million for corporate purposes; the remainder represents capital expenditures relating to the Double E Project.

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

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

Segment adjusted EBITDA by reportable segment follows.

	Three months ended March 31,
	2020		2019
	(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	5,928	$	6,193
Ohio Gathering		7,939		9,210
Williston Basin		16,192		18,734
DJ Basin		5,911		2,673
Permian Basin		1,581		(550	)
Piceance Basin		23,557		25,999
Barnett Shale		8,760		11,374
Marcellus Shale		5,320		5,142
Total of reportable segments' measures of profit	$	75,188	$	78,775

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

	Three months ended March 31,
	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	$	1,970		$	(36,266	)
Add:
Corporate and Other expense		11,895			14,159
Interest expense		20,218			17,527
Deferred Purchase Price Obligation		2,297			4,427
Depreciation and amortization		29,863			28,116
Proportional adjusted EBITDA for equity method investees		7,939			9,210
Adjustments related to MVC shortfall payments		(5,442	)		(4,199	)
Adjustments related to capital reimbursement activity		(211	)		(715	)
Unit-based and noncash compensation		2,723			2,526
Loss (gain) on asset sales, net		115			(961	)
Long-lived asset impairment		3,821			44,951
Total of reportable segments' measures of profit	$	75,188		$	78,775

Adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC (see Note 3). Contributions in aid of construction are recognized over the remaining term of the respective contract. We include adjustments related to capital reimbursement activity in our calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction.

Adjustments related to MVC shortfall payments by reportable segment follow.

	Three months ended March 31, 2020
	Williston Basin			Piceance Basin		Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(5,665	)	$	223	$	—	$	(5,442	)

	Three months ended March 31, 2019
	Williston Basin			Piceance Basin			Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(5,549	)	$	(103	)	$	1,453	$	(4,199	)

5. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	March 31, 2020		December 31, 2019
	(In thousands)
Gathering and processing systems and related equipment	$	2,193,225	$	2,182,950
Construction in progress		73,040		78,716
Land and line fill		10,440		10,137
Other		57,548		53,129
Total		2,334,253		2,324,932
Less accumulated depreciation		464,371		442,681
Property, plant and equipment, net	$	1,869,882	$	1,882,251

In March 2020, in connection with the cancellation of a compressor station project in the DJ Basin due to delays in customer drilling plans, we 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, we performed a recoverability assessment of certain assets within these reporting segments.

Also in March 2019, in the DJ Basin we determined that certain processing plant assets related to our existing 20 MMcf/d plant would no longer be utilized due to our 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, we recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019.

In March 2019, in the Barnett Shale we determined that certain compressor station assets would be shut down and decommissioned. As a result, we recorded an impairment charge of $9.7 million related to these assets in the first quarter of 2019. See Note 6 for additional details.

Depreciation expense and capitalized interest follow.

	Three months ended March 31,
	2020		2019
	(In thousands)
Depreciation expense	$	21,661	$	19,783
Capitalized interest		491		1,915

6. AMORTIZING INTANGIBLE ASSETS

Details regarding our intangible assets, all of which are subject to amortization, follow:

	March 31, 2020
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(15,359	)	$	8,836
Contract intangibles		278,448		(175,973	)		102,475
Rights-of-way		157,175		(44,410	)		112,765
Total intangible assets	$	459,818	$	(235,742	)	$	224,076

	December 31, 2019
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(15,125	)	$	9,070
Contract intangibles		278,448		(169,549	)		108,899
Rights-of-way		157,175		(42,866	)		114,309
Total intangible assets	$	459,818	$	(227,540	)	$	232,278

In March 2019, certain events occurred which indicated that certain long-lived assets relating to the Barnett Shale reporting segment could be impaired (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of rights-of-way intangible assets. We concluded the rights-of-way intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019.

We recognized amortization expense in Other revenues as follows:

	Three months ended March 31,
	2020			2019
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(234	)	$	(389	)

We recognized amortization expense in costs and expenses as follows:

	Three months ended March 31,
	2020		2019
	(In thousands)
Amortization expense – contract intangibles	$	6,424	$	6,397
Amortization expense – rights-of-way		1,544		1,547

The estimated aggregate annual amortization expected to be recognized for the remainder of 2020 and each of the four succeeding fiscal years follows.

	Intangible assets
	(In thousands)
2020	$	23,926
2021		28,209
2022		25,142
2023		25,088
2024		14,917

7. EQUITY METHOD INVESTMENTS

Double E

In June 2019, we formed Double E in connection with the Double E Project. Effective June 26, 2019, Summit Permian Transmission, a wholly owned and consolidated subsidiary of the Partnership, and an affiliate of Double E’s foundation shipper (the “JV Partner”) executed an agreement whereby Double E will provide natural gas transportation services from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas (the “Double E Agreement”). Concurrent with the Double E Agreement, we issued a parental guaranty to fund any capital calls not satisfied by Summit Permian Transmission during the construction of the Double E Project, for an amount not to exceed $350.0 million. The Partnership has guaranteed, among other things, payment of our pro rata share of the required capital calls during construction of the Double E Project and, as of March 31, 2020, we estimate that our pro rata share of our remaining capital contributions is approximately $251 million. In connection with the Double E Agreement and the related Double E Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and our JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Double E Agreement, Double E distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, we made additional cash investments of $18.3 million through December 31, 2019.

During the three months ended March 31, 2020, we made cash investments of $58.0 million in the Double E Project. Upon completion of the Double E Project, we expect to own at least a 50% interest in the Double E Project. We are leading the development, permitting and construction of the Double E Project and expect to operate the pipeline upon commissioning. At our current 70% interest, we estimate that our total share of the capital expenditures required to develop the Double E Project will total approximately $350.0 million.

Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Double E Agreement, Summit Permian Transmission was not deemed to be the primary beneficiary due to the JV Partner’s voting rights on significant matters. We account for our ownership interest in Double E as an equity method investment because we have significant influence over Double E. Our portion of Double E’s net assets, which was $92.3 million at March 31, 2020, is reported under the caption Investment in equity method investees on the unaudited condensed consolidated balance sheet.

For the three months ended March 31, 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

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

As of March 31, 2020 and December 31, 2019, our ownership interest in Ohio Gathering was 38.5%.

A reconciliation of our 38.5% ownership interest in Ohio Gathering to our investment per Ohio Gathering's books and records follows (in thousands).

Investment in Ohio Gathering, March 31, 2020	$	271,268
March cash distributions		1,875
Basis difference		223,151
Investment in Ohio Gathering February 29, 2020	$	496,294

As noted in our 2019 Annual Report, in December 2019 an impairment loss of long-lived assets was recognized by OCC which brought our investment in OCC to zero. As a result, we have not recorded our portion of OCC’s net loss for the three months ended March 31, 2020 in the Income (loss) from equity method investees caption of our unaudited condensed consolidated statements of operations.

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

	Three months ended February 29, 2020					Three months ended February 28, 2019
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	30,068	$	2,727		$	33,466	$	2,266
Total operating expenses		25,750		30,855			25,487		2,973
Net income (loss)		4,311		(28,128	)		7,972		(707	)

8. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2020	$	18	$	1,933	$	2,860	$	7,014	$	1,630	$	38	$	13,493
Additions		2		483		2,123		1,547		396		9		4,560
Less revenue recognized		5		483		1,285		1,544		409		9		3,735
Current deferred revenue, March 31, 2020	$	15	$	1,933	$	3,698	$	7,017	$	1,617	$	38	$	14,318

A rollforward of noncurrent deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2020	$	3	$	3,634	$	7,589	$	17,710	$	9,575	$	198	$	38,709
Additions		425		3,522		3,263		1,304		382		—		8,896
Less reclassification to current deferred revenue		2		483		2,123		1,547		396		9		4,560
Noncurrent deferred revenue, March 31, 2020	$	426	$	6,673	$	8,729	$	17,467	$	9,561	$	189	$	43,045

9. DEBT

Debt consisted of the following:

	March 31, 2020			December 31, 2019
	(In thousands)
Summit Holdings' variable rate senior secured Revolving Credit Facility (3.74% at March 31, 2020 and 4.55% at December 31, 2019) due May 2022	$	698,000		$	677,000
Summit Holdings' 5.5% senior unsecured notes due August 2022		300,000			300,000
Less unamortized debt issuance costs (1)		(1,521	)		(1,686	)
Summit Holdings' 5.75% senior unsecured notes due April 2025		500,000			500,000
Less unamortized debt issuance costs (1)		(4,763	)		(5,015	)
Total long-term debt	$	1,491,716		$	1,470,299

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

Revolving Credit Facility. Summit Holdings has a senior secured 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. As of March 31, 2020, SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of, the indebtedness outstanding under the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 1.75% or the adjusted Eurodollar rate, as defined in the credit agreement, plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At March 31, 2020, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 3.74% and the unused portion of the Revolving Credit Facility totaled $542.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of March 31, 2020 was approximately $120 million. See Note 15 for additional information on our letter of credit.

As of March 31, 2020, we had $5.5 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in Other noncurrent assets on the unaudited condensed consolidated balance sheet.

As of and during the three months ended March 31, 2020, we were in compliance with the Revolving Credit Facility's financial covenants. There were no defaults or events of default during the three months ended March 31, 2020.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "5.5% Senior Notes" and, together with the 5.75% Senior Notes (defined below), the “Senior Notes”) as described in the 2019 Annual Report.

In February 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes (the "5.75% Senior Notes") maturing April 15, 2025 as described in the 2019 Annual Report.

The Guarantor Subsidiaries are 100% owned by a subsidiary of SMLP. The Guarantor Subsidiaries and SMLP fully and unconditionally and jointly and severally guarantee the Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013. We have no other independent assets or operations. At no time have the Senior Notes been guaranteed by the Co-Issuers.

As of and during the three months ended March 31, 2020, we were in compliance with the covenants governing our Senior Notes. There were no defaults or events of default during the three months ended March 31, 2020.

10. FINANCIAL INSTRUMENTS

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

Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit or other forms of credit assurance for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top five customers or counterparties accounted for 49% of total accounts receivable as of March 31, 2020, compared with 46% as of December 31, 2019.

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

The Deferred Purchase Price Obligation's carrying value is its fair value because carrying value represents the present value of the payment which can be made at any time prior to January 15, 2022. In November 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion (see Note 16 for additional information).

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

	March 31, 2020				December 31, 2019
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings 5.5% Senior Notes ($300.0 million principal)	$	298,479	$	58,875	$	298,314	$	266,750
Summit Holdings 5.75% Senior Notes ($500.0 million principal)		495,237		53,125		494,985		382,708

The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to its floating interest rate. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of March 31, 2020 and December 31, 2019. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

11. PARTNERS' CAPITAL AND MEZZANINE CAPITAL

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

	Series A Preferred Units		Common Units
Units, December 31, 2019		300,000		93,493,473
Net units issued under the SMLP LTIP		—		975,912
Units, March 31, 2020		300,000		94,469,385

GP/IDR Exchange. On March 22, 2019, we cancelled our IDRs and converted our 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units which were issued to SMP Holdings in the Equity Restructuring. These units had a fair value of $84.5 million as of the transaction date (March 22, 2019). As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. Energy Capital Partners continues to control the non-economic GP interest in SMLP.

Our General Partner held IDRs (through the Equity Restructuring). Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the three months ended March 31 follow.

	Three months ended March 31,
	2020		2019
	(In thousands)
IDR payments	$	—	$	2,139

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

Series A Preferred Units. In 2017, we 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.

Subsidiary Series A Preferred Units. In December 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit as described in the 2019 Annual Report.

During the three months ended March 31, 2020, we issued an additional 35,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $33.9 million (after deducting underwriting discounts and offering expenses) to fund our share of capital expenses associated with the Double E Project.

The proceeds associated with the issuance of Subsidiary Series A Preferred Units are classified as restricted cash on the accompanying unaudited condensed consolidated balance sheets in accordance with the underlying agreement with TPG Energy Solutions Anthem, L.P. until the related funding is used for the Double E Project.

Cash Distributions Paid and Declared. We paid the following per-unit distributions during the three months ended March 31:

	Three months ended March 31,
	2020		2019
Per-unit distributions to unitholders	$	0.125	$	0.575

With respect to our Subsidiary Series A Preferred Units relating to the first quarter of 2020, we declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted in the issuance of 907 Subsidiary Series A Preferred Units. This PIK amount equates to a distribution of $13.9433 per Subsidiary Series A Preferred Unit for the first quarter in 2020, or $70 on an annualized basis. In addition, we 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 three months ended March 31, 2020.

12. EARNINGS PER UNIT

The following table details the components of EPU.

	Three months ended March 31,
	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	$	5,309		$	(36,926	)
Less net income attributable to Series A Preferred Units		7,125			7,125
Less net income attributable to Subsidiary Series A Preferred Units		945			—
Net loss attributable to common limited partners	$	(2,761	)	$	(44,051	)

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – diluted		93,675			75,793

Loss per limited partner unit:
Common unit – basic	$	(0.03	)	$	(0.58	)
Common unit – diluted	$	(0.03	)	$	(0.58	)

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		1,889			34

13. UNIT-BASED AND NONCASH COMPENSATION

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

•

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

•

In March 2020, we also issued 549,450 common units to our three independent directors in connection with their annual compensation plan.

•

During the three months ended March 31, 2020, 418,999 phantom units vested.

•

In March 2020, we 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 March 31, 2020, approximately 6.9 million common units remained available for future issuance under the SMLP LTIP.

14. RELATED-PARTY TRANSACTIONS

Acquisitions. See Notes 1 and 17 of the 2019 Annual Report.

Reimbursement of Expenses from General Partner. Our General Partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The "Due to affiliate" line item on the unaudited condensed consolidated balance sheet represents the payables to our General Partner for expenses incurred by it and paid on our behalf.

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

	Three months ended March 31,
	2020		2019
	(In thousands)
Operation and maintenance expense	$	5,575	$	7,885
General and administrative expense		7,841		10,830

15. LEASES, COMMITMENTS AND CONTINGENCIES

Leases. We account for leases in accordance with ASC Topic 842. We and Summit Investments lease and sublease certain office space and equipment under operating leases. We sublease office space for our corporate headquarters in Houston as well as for corporate offices in Dallas, Denver and Atlanta and offices in and around our gathering systems for terms of between three and ten years. We lease and sublease the office space to limit exposure to risks related to ownership, such as fluctuations in real estate prices. In addition, we lease equipment primarily to support our operations in response to the needs of our gathering systems for terms of between three and four years. We and Summit Investments also lease vehicles under finance leases to support our operations in response to the needs of our gathering systems for a term of three years. We only lease from reputable companies and our leased assets are not specialized in our industry.

Some of our leases are subject to annual escalations according to the Consumer Price Index (“CPI”). While lease liabilities are not remeasured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred.

We have options to extend the lease and sublease terms of certain office space in Texas, Colorado and West Virginia. The beginning of the noncancelable lease and sublease period for these agreements ranges from 2014 to 2020 and the lease and sublease period ends between 2020 and 2028. These lease and sublease agreements contain between one and three options to renew the lease and sublease for a period of between two and five years. As of March 31, 2020, the exercise of the renewal options for these agreements are not reasonably certain and, as a result, the payments associated with these renewals are not included in the measurement of the lease liability and right-of-use (“ROU”) asset.

We also have options to extend the lease term of certain compression equipment used at the Summit Utica gathering system. The beginning of the noncancelable lease period for these leases is 2017 and the lease period ends in 2020. In April 2020, we renewed the lease period for periods of one to three years. Our future minimum lease payments are approximately $2.3 million.

Our leases do not contain residual value guarantees.

In accordance with the provisions in our Revolving Credit Facility, our aggregate finance lease obligations cannot exceed $50 million in any period of twelve consecutive calendar months during the life of such leases.

In March 2019, we entered into an agreement with a third party vendor to construct a transmission line to deliver electric power to the new 60 MMcf/d processing plant in the DJ Basin. The project is expected to cost approximately $7.8 million and we made an up-front payment of $3.0 million, which is included in the Property, plant and equipment, net caption on the unaudited condensed consolidated balance sheet. During the second quarter of 2019, we exercised an option to increase the capacity of the transmission line for an additional cost of $4.3 million and we issued an irrevocable standby letter of credit payable to the vendor with an initial term of one year totaling $9.1 million, which reflects the expected remaining cost of the project. The letter of credit will automatically renew for successive twelve-month periods following the initial term, subject to certain adjustments. Once construction is complete, the letter of credit will be adjusted to reflect the final construction cost. We determined the contract contained a lease based on the right to use the constructed transmission line to power the processing plant in the DJ Basin. The project is expected to be completed and the commencement date of the ROU asset will be on or before January 2021.

Our significant assumptions or judgments include the determination of whether a contract contains a lease and the discount rate used in our lease liabilities.

The rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term used. Our incremental borrowing rate on the Revolving Credit Facility was 4.55% at December 31, 2019, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.

ROU assets (included in the Property, plant and equipment, net caption on our unaudited condensed consolidated balance sheet) and lease liabilities (included in the Other current liabilities and Other noncurrent liabilities captions on our unaudited condensed consolidated balance sheet) follow:

	March 31, 2020		December 31, 2019
	(In thousands)

ROU assets
Operating	$	4,306	$	3,580
Finance		2,649		3,159
	$	6,955	$	6,739
Lease liabilities, current
Operating	$	967	$	1,221
Finance		1,023		1,246
	$	1,990	$	2,467
Lease liabilities, noncurrent
Operating	$	3,482	$	2,513
Finance		483		676
	$	3,965	$	3,189

Lease cost and Other information follow:

	Three months ended March 31,
	2020		2019
	(In thousands)
Lease cost
Finance lease cost:
Amortization of ROU assets (included in depreciation and amortization)	$	352	$	368
Interest on lease liabilities (included in interest expense)		18		23
Operating lease cost (included in general and administrative expense)		772		832
	$	1,142	$	1,223

	Three months ended March 31,
	2020			2019
	(In thousands)
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash outflows from operating leases	$	708		$	821
Operating cash outflows from finance leases		18			23
Financing cash outflows from finance leases		417			445
ROU assets obtained in exchange for new operating lease liabilities		1,199			—
ROU assets obtained in exchange for new finance lease liabilities		—			693
Weighted-average remaining lease term (years) - operating leases		6.0			3.5
Weighted-average remaining lease term (years) - finance leases		2.0			2.0
Weighted-average discount rate - operating leases		5	%		5	%
Weighted-average discount rate - finance leases		4	%		4	%

We recognize total lease expense incurred or allocated to us in general and administrative expenses. Lease expense related to operating leases, including lease expense incurred on our behalf and allocated to us, was as follows:

	Three months ended March 31,
	2020		2019
	(In thousands)
Lease expense	$	912	$	944

Future minimum lease payments due under noncancelable leases for the remainder of 2020 and each of the five succeeding fiscal years and thereafter, were as follows:

	March 31, 2020
	(In thousands)
	Operating		Finance
2020	$	1,046	$	873
2021		1,125		606
2022		883		76
2023		741		—
2024		555		—
2025		464		—
Thereafter		742		—
Total future minimum lease payments	$	5,556	$	1,555

Future minimum lease payments due under noncancelable leases at December 31, 2019 and each of the five succeeding fiscal years and thereafter, were as follows:

	December 31, 2019
	(In thousands)
	Operating		Finance
2020	$	1,705	$	1,299
2021		1,004		616
2022		551		76
2023		408		—
2024		240		—
2025		153		—
Thereafter		742		—
Total future minimum lease payments	$	4,803	$	1,991

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

As described in the 2019 Annual Report, in 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, which was covered by Summit Investments' insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. Summit Investments exhausted the $25.0 million pollution liability policy in 2015.

A rollforward of the aggregate accrued environmental remediation liabilities follows.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2020	$	4,651
Payments made		(17	)
Accrued environmental remediation, March 31, 2020	$	4,634

As of March 31, 2020, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines

expected to be incurred subsequent to March 31, 2021. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

While we cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident, we believe at this time that it is unlikely that SMLP or its General Partner will be subject to any material liability as a result of any governmental proceeding related to the rupture, unless Summit Investments is unable to pay government fines or its subsidiary, Summit Midstream Partners Holdings, LLC, is unable to honor its indemnity obligations associated with the 2016 sale of Meadowlark Midstream to SMLP.

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.

16. DISPOSITIONS, DROP DOWN TRANSACTIONS AND RESTRUCTURING

Tioga Midstream Disposition. In February 2019, Tioga Midstream, LLC, a subsidiary of SMLP, and certain affiliates of SMLP (collectively, “Summit”) 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 Summit 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, Summit 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 our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

2016 Drop Down. In 2016, SMLP acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets. These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin, as well as ownership interests in Ohio Gathering.

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

On November 7, 2019, we and SMP Holdings entered into the Second Amendment to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made the November 2019 Prepayment. In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion.

As of March 31, 2020, the Remaining Consideration of the Deferred Purchase Price Obligation was $180.75 million on the unaudited condensed consolidated balance sheet.

Restructuring Activities. In 2019, our management approved and initiated a plan to restructure our operations resulting in certain management, facility and organizational changes. During the three months ended March 31, 2020, we expensed costs of approximately $2.8 million associated with restructuring activities. These activities consisted

primarily of employee-related costs and consulting costs in support of the project. These costs are included within the General and administrative caption on the unaudited condensed consolidated statement of operations.

As of March 31, 2020, the components of our restructuring plan are as follows:

•

Employee-related costs — We reorganized our workforce and eliminated redundant or unneeded positions. In connection with the workforce restructuring, we expect to incur severance, benefits and other employee related costs of approximately $4.1 million over the next nine months following March 31, 2020. During the three months ended March 31, 2020, we expensed approximately $1.9 million primarily related to severance, redundant salaries, certain bonuses and other employee benefits in connection with our plan. As of March 31, 2020, cash payments were made of approximately $2.1 million and we had approximately $2.4 million included in the Other current liabilities caption on the unaudited condensed consolidated balance sheets for these costs, which we expect to pay over the remainder of the year.

•

Consultants — We engaged third-party consulting firms to assist in the evaluation of the Partnership’s cost structure, to help formulate the plan to implement the project, and to provide project management services for certain project initiatives. During the three months ended March 31, 2020, we expensed approximately $0.9 million related to these services. As of March 31, 2020, cash payments of approximately $1.1 million were made and we had approximately $0.4 million included in the Other current liabilities caption on the unaudited condensed consolidated balance sheets for these costs, which we expect to pay over the remainder of the year. We expect to incur an additional $0.2 million related to consulting costs to be incurred over the next nine months following March 31, 2020.

17. SUBSEQUENT EVENTS

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

On May 3, 2020, we entered into a purchase agreement with Energy Capital Partners (“ECP”) and certain of its affiliates (the “Purchase Agreement”) pursuant to which we agreed to acquire Summit Investments in exchange for approximately $35 million in cash and warrants for the purchase of up to an aggregate of 10,000,000 common units (the “GP Buy-In Transaction”). Summit Investments is the sole member of SMP Holdings, which in turn owns (i) our General Partner, (ii) 34,604,581 SMLP common units pledged as collateral under the SMPH Term Loan, (iii) 10,714,285 SMLP common units not pledged as collateral and (iv) the right to receive the Deferred Purchase Price Obligation. The terms of the Purchase Agreement were unanimously approved by the conflicts committee (the “Conflicts Committee”) of the Board of Directors, comprised solely of independent directors, and was unanimously approved by the Board of Directors. The Purchase Agreement contains customary representations and warranties and covenants by each of the parties, and various closing conditions and termination rights, all as detailed in the Partnership’s Current Report on Form 8-K filed with the SEC on May 5, 2020.

At the closing of the GP Buy-In Transaction, Summit Holdings, a Delaware limited liability company and wholly owned subsidiary of the Partnership (the “Borrower”), will borrow an aggregate principal amount of $35 million from certain affiliates of ECP pursuant to two separate term loan agreements that will mature on March 31, 2021 (“Term Loan Credit Agreements”), and upon the terms and subject to the other conditions set forth therein (the “Loans”). The Loans under the Term Loan Credit Agreements will bear interest at a rate of 8.00% per annum, and will generally be (i) guaranteed by the Partnership and each subsidiary of the Borrower that guarantees the obligations under the Borrower’s Revolving Credit Facility, and (ii) secured by a first priority lien on and security interest in all property that secures the obligations under the Revolving Credit Facility.

The summaries of the Purchase Agreement and the Term Loan Credit Agreements contained in this Quarterly Report on Form 10-Q do not purport to be complete and are qualified in their entirety by reference to the Partnership’s Current Report on Form 8-K filed with the SEC on May 5, 2020.

Simultaneously with the execution of the Purchase Agreement, the Partnership immediately suspended its distributions to holders of its common units and suspended payment of distributions to holders of its Series A

Preferred Units representing limited partner interests in the Partnership, commencing with respect to the quarter ending March 31, 2020.

Upon closing of the GP Buy-In Transaction, all directors affiliated with ECP will resign from the Board of Directors. Going forward, the Board of Directors will consist of a majority of independent directors. Upon the closing of the GP Buy-In Transaction, the Third Amended and Restated Agreement of Limited Partnership of the Partnership will be amended and restated, and the Amended and Restated Limited Liability Company Agreement of the GP will be amended and restated, to, among other things, provide the holders of common units with voting rights in the election of directors of the Board of Directors on a staggered basis beginning in 2022.

On April 10, 2020, we received a formal notice from the New York Stock Exchange (“NYSE”) 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 six months following the receipt of the formal noncompliance notice to cure the deficiency and regain compliance. During this period, our common units will continue trading on the NYSE under our existing ticker symbol, with the addition of a suffix indicating the "below criteria" status of our common units, as "SMLP.BC." We intend to regain compliance with the NYSE listing standards by pursuing measures which include (i) enhanced capital discipline and operating margins, including a planned 30% reduction in 2020 capital expenditures and ongoing implementation of expense savings initiatives; (ii) debt reduction through capital markets transactions and asset sales; and potentially (iii) consummation of a reverse unit split, subject to approval from our board of directors.

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

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Critical Accounting Estimates

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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:

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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.

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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.

We are the owner-operator of or have significant ownership interests in the following gathering and transportation systems, which comprise our Core Focus Areas:

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

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Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

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Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico; and

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We are the owner-operator of the following gathering systems, which comprise our Legacy Areas:

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Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;

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DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

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

For additional information on our organization and systems, see Notes 1 and 4 to the unaudited condensed consolidated financial statements.

Our financial results are driven primarily by volume throughput 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 months ended March 31, 2020, these additional activities accounted for approximately 13% 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 Months Ended March 31, 2020 and 2019" section herein.

	Three months ended March 31,
	2020		2019
	(In thousands)
Net income (loss)	$	5,309	$	(36,914	)
Reportable segment adjusted EBITDA
Utica Shale	$	5,928	$	6,193
Ohio Gathering		7,939		9,210
Williston Basin		16,192		18,734
DJ Basin		5,911		2,673
Permian Basin		1,581		(550	)
Piceance Basin		23,557		25,999
Barnett Shale		8,760		11,374
Marcellus Shale		5,320		5,142

Net cash provided by operating activities	$	73,968	$	52,711
Capital expenditures (1)		18,583		60,848
Investment in equity method investee		58,033		—

Distributions to common unitholders	$	11,702	$	45,281
Net borrowings (repayments) under Revolving Credit Facility		21,000		(32,000	)
Proceeds from issuance of Subsidiary Series A preferred units, net of costs (2)		33,946		—

(1) See "Liquidity and Capital Resources" herein and Note 4 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.

Three months ended March 31, 2020. The following items are reflected in our financial results:

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Three months ended March 31, 2019. The following items are reflected in our financial results:

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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.

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In February 2019, we signed an amendment to the Contribution Agreement related to the 2016 Drop Down pursuant to which, on April 1, 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation. Following the payment, the Remaining Consideration was fixed at $303.5 million, with such amount being payable by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020.

The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid.

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On March 22, 2019, pursuant to an equity restructuring agreement with the General Partner and SMP Holdings, we cancelled our IDRs and converted our 2% economic GP interest into a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings (the “Equity Restructuring”). As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. ECP continues to control the non-economic GP interest in SMLP.

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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 would be shut down and de-commissioned beginning in the second quarter of 2019 and we recorded an impairment charge of $10.2 million related to these assets.

Trends and Outlook

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

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

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Production from U.S. shale plays;

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Capital markets availability and cost of capital;

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Shifts in operating costs and inflation; and

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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 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 quarter of 2020, only one month of the quarter was affected by COVID-19 and if the current conditions continue, subsequent quarters may reflect these conditions for a full quarter. 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. 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 new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. 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 enhanced 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. 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, 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. 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 weeks we have collaborated extensively with our customer base regarding reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given further deterioration of market conditions in March and April 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 and DJ Basin reportable segments. Accordingly, we now expect 2020 total capital expenditures to range from of $30 million to $50 million.

The full extent to which our operations may be impacted by the COVID-19 pandemic and reduced demand and pricing for oil will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

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

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

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the Utica Shale, which is served by Summit Utica;

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

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

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

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the Permian Basin, which is served by Summit Permian;

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the Piceance Basin, which is served by Grand River;

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

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the Marcellus Shale, which is served by Mountaineer Midstream.

Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 16 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream.

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

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throughput volume;

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revenues;

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operation and maintenance expenses; and

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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 months ended March 31, 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 to the unaudited condensed consolidated financial statements.

Results of Operations

Consolidated Overview for the Three Months Ended March 31, 2020 and 2019

The following table presents certain consolidated and operating data.

	Three months ended March 31,
	2020			2019
	(In thousands)
Revenues:
Gathering services and related fees	$	83,792		$	86,964
Natural gas, NGLs and condensate sales		13,780			37,928
Other revenues		7,331			6,516
Total revenues		104,903			131,408
Costs and expenses:
Cost of natural gas and NGLs		8,225			31,759
Operation and maintenance		21,811			24,222
General and administrative		16,378			17,281
Depreciation and amortization		29,629			27,727
Transaction costs		11			950
Loss (gain) on asset sales, net		115			(961	)
Long-lived asset impairment		3,821			44,951
Total costs and expenses		79,990			145,929
Other (expense) income		(428	)		209
Interest expense		(20,218	)		(17,527	)
Deferred Purchase Price Obligation		(2,297	)		(4,427	)
Income (loss) before income taxes and income (loss) loss from equity method investees		1,970			(36,266	)
Income tax benefit (expense)		28			(207	)
Income (loss) from equity method investees		3,311			(441	)
Net income (loss)	$	5,309		$	(36,914	)

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,281			1,462
Aggregate average daily throughput - liquids (Mbbl/d)		98			103

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

Volumes – Gas. Natural gas throughput volumes decreased 181 MMcf/d for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily reflecting:

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a volume throughput decrease of 102 MMcf/d for the Piceance Basin segment.

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a volume throughput decrease of 64 MMcf/d for the Utica Shale segment.

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a volume throughput decrease of 27 MMcf/d for the Barnett Shale segment.

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a volume throughput decrease of 15 MMcf/d for the Marcellus Shale segment.

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a volume throughput increase of 18 MMcf/d for the Permian Basin segment.

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a volume throughput increase of 11 MMcf/d for the DJ Basin segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 5 Mbbl/d for the three months ended March 31, 2020 compared to the three months ended March 31, 2019.

For additional information on volumes, see the "Segment Overview for the Three Months Ended March 31, 2020 and 2019" section herein.

Revenues. Total revenues decreased $26.5 million during the three months ended March 31, 2020 compared to the prior year period primarily comprised of a $24.1 million decrease in natural gas, NGLs and condensate sales and a $3.2 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $3.2 million compared to the three months ended March 31, 2019, primarily reflecting:

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a $2.6 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 $1.5 million 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.

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a $4.7 million decrease in gathering services and related fees in the Piceance Basin relating 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.

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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 partially offset by the completion of new wells throughout 2019 and in the first quarter of 2020, and a more favorable volume and gathering rate mix from customers.

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a $1.9 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a $1.5 million decrease in gathering services and related fees attributable to natural production declines and the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019.

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a $3.1 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, partially offset by natural production declines.

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a $1.9 million increase in gathering services and related fees in the Permian Basin due to higher volume growth from ongoing drilling and completion activity.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $24.1 million compared to the three months ended March 31, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $23.5 million decrease in natural gas, NGL and condensate purchases.

Costs and Expenses. Total costs and expenses decreased $65.9 million during the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily reflecting:

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the impact of the March 2019 recognition of $34.9 million of certain long-lived asset impairments in the DJ Basin.

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a $23.5 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.

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the impact of the March 2019 recognition of $10.2 million of certain long-lived asset impairments in the Barnett Shale.

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the recognition in March 2020 of $3.6 million of certain long-lived asset impairments in the DJ Basin.

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a $2.4 million decrease in operation and maintenance expense primarily due to a $1.4 million decrease in salaries and benefits costs and a $0.9 million decrease in property taxes.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $23.5 million during the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.

Operation and Maintenance. Operation and maintenance expense decreased $2.4 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to a $1.3 million decrease in salaries and benefits costs and a $0.9 million decrease in property taxes.

General and Administrative. General and administrative expense decreased $0.9 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was primarily due to the acceleration of depreciation on certain Williston Basin assets.

Transaction Costs. The decrease in transaction costs recognized during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to the financial advisory costs associated primarily with the Equity Restructuring that occurred in 2019.

Interest Expense. The increase in interest expense for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, was primarily due to a higher average outstanding balance on the Revolving Credit Facility.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the three months ended March 31, 2020 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 16 to the unaudited condensed consolidated financial statements).

For additional information, see the "Segment Overview for the Three Months Ended March 31, 2020 and 2019" and "Corporate and Other Overview for the Three Months Ended March 31, 2020 and 2019" sections herein.

Segment Overview for the Three Months Ended March 31, 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 March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		222		286	(22%)

Volume throughput declined compared to the three months ended March 31, 2019 as a result of natural production declines from existing wells partially offset by the completion of new wells throughout 2019 and in the first quarter of 2020, and a more favorable volume and gathering rate mix from customers.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,962		$	7,495		(7%)
Total revenues		6,962			7,495		(7%)
Costs and expenses:
Operation and maintenance		941			1,216		(23%)
General and administrative		88			81		9%
Depreciation and amortization		1,927			1,908		1%
Loss on asset sales, net		16			—		*
Total costs and expenses		2,972			3,205		(7%)
Add:
Depreciation and amortization		1,927			1,908
Adjustments related to capital reimbursement activity		(5	)		(5	)
Loss on asset sales, net		16			—
Segment adjusted EBITDA	$	5,928		$	6,193		(4%)

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $0.3 million compared to the three months ended March 31, 2019.

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

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

	Ohio Gathering
	Three months ended March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		610		711	(14%)

Volume throughput for the Ohio Gathering system in 2020 decreased compared to the year ended December 31, 2019 as a result of natural production declines on existing wells on the system 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 March 31,
	2020		2019		Percentage Change
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	7,939	$	9,210	(14%)
Segment adjusted EBITDA	$	7,939	$	9,210	(14%)

Segment adjusted EBITDA for equity method investees decreased $1.3 million compared to the three months ended March 31, 2019 primarily as a result of the lower volume throughput described above.

Williston Basin. The Polar and Divide, Bison Midstream and Tioga Midstream (through March 22, 2019; refer to Note 16 to the unaudited condensed consolidated financial statements 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 March 31,
	2020		2019		Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)		14		16	(13%)

Aggregate average daily throughput - liquids (Mbbl/d)		98		103	(5%)

Natural gas. Natural gas volume throughput decreased compared to the three months ended March 31, 2019, primarily reflecting natural production declines and the sale of Tioga Midstream partially offset by the completion of new wells behind the Bison Midstream system in 2019 and 2020.

Liquids. The decrease in liquids volume throughput compared to the three months ended March 31, 2019, primarily reflected natural production declines and the sale of Tioga Midstream partially offset by the completion of new wells throughout 2019.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	23,797		$	25,706		(7%)
Natural gas, NGLs and condensate sales		4,324			5,585		(23%)
Other revenues		3,142			2,908		8%
Total revenues		31,263			34,199		(9%)
Costs and expenses:
Cost of natural gas and NGLs		1,663			2,709		(39%)
Operation and maintenance		6,722			6,516		3%
General and administrative		538			341		58%
Depreciation and amortization		6,495			5,436		19%
Loss (gain) on asset sales, net		49			(968	)	*
Long-lived asset impairment		—			10		*
Total costs and expenses		15,467			14,044		10%
Add:
Depreciation and amortization		6,495			5,436
Adjustments related to MVC shortfall payments		(5,665	)		(5,549	)
Adjustments related to capital reimbursement activity		(483	)		(350	)
Loss (gain) on asset sales, net		49			(968	)
Long-lived asset impairment		—			10
Segment adjusted EBITDA	$	16,192		$	18,734		(14%)

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.5 million compared to the three months ended March 31, 2019 primarily reflecting:

•

a decrease of $0.9 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the three months ended March 31, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput and lower liquids volume throughput on our systems.

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 March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		32		21	52%

Volume throughput increased compared to the three months ended March 31, 2019, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines.

Financial data for our DJ Basin reportable segment follows.

	DJ Basin
	Three months ended March 31,
	2020		2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,855	$	3,724		84%
Natural gas, NGLs and condensate sales		70		85		(18%)
Other revenues		1,034		1,007		3%
Total revenues		7,959		4,816		65%
Costs and expenses:
Cost of natural gas and NGLs		9		10		*
Operation and maintenance		2,516		1,849		36%
General and administrative		82		72		14%
Depreciation and amortization		1,527		799		91%
Long-lived asset impairment		3,635		34,721		*
Total costs and expenses		7,769		37,451		(79%)
Add:
Depreciation and amortization		1,527		799
Adjustments related to capital reimbursement activity		559		(212	)
Long-lived asset impairment		3,635		34,721
Segment adjusted EBITDA	$	5,911	$	2,673		121%

* Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA increased $3.2 million compared to the three months ended March 31, 2019, primarily reflecting:

•

a $3.1 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity, a more favorable volume and gathering rate mix from customers, and the commissioning of our new natural gas processing plant in June 2019. This was partially offset by natural production declines.

Other items to note:

•

During the quarter ended March 31, 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the unaudited condensed consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the three months ended March 31, 2020.

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 March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		33		15	120%

Volume throughput increased compared to the three months ended March 31, 2019, primarily as a result of ongoing drilling and completion activity across our service area.

Financial data for our Permian Basin reportable segment follows.

	Permian Basin
	Three months ended March 31,
	2020		2019			Percentage Change
	(In thousands)
Revenues:
Gathering services and related fees	$	2,311	$	366		531%
Natural gas, NGLs and condensate sales		4,512		4,221		7%
Other revenues		187		32		484%
Total revenues		7,010		4,619		52%
Costs and expenses:
Cost of natural gas and NGLs		4,149		4,245		(2%)
Operation and maintenance		1,187		891		33%
General and administrative		93		33		182%
Depreciation and amortization		1,345		1,072		25%
Loss on asset sales, net		4		—		*
Long-lived asset impairment		182		—		*
Total costs and expenses		6,960		6,241		12%
Add:
Depreciation and amortization		1,345		1,072
Loss on asset sales, net		4		—
Long-lived asset impairment		182		—
Segment adjusted EBITDA	$	1,581	$	(550	)	*

*Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA increased $2.1 million compared to the three months ended March 31, 2019, primarily reflecting a $1.9 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.

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 March 31,
	2020		2019		Percentage Change
Aggregate average daily throughput (MMcf/d)		383		485	(21%)

Volume throughput decreased compared to the three months ended March 31, 2019, as a result of a natural production declines.

Financial data for our Piceance Basin reportable segment follows.

	Piceance Basin
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	27,189		$	31,840		(15%)
Natural gas, NGLs and condensate sales		1,003			2,302		(56%)
Other revenues		1,065			1,138		(6%)
Total revenues		29,257			35,280		(17%)
Costs and expenses:
Cost of natural gas and NGLs		457			1,473		(69%)
Operation and maintenance		4,938			7,299		(32%)
General and administrative		285			294		(3%)
Depreciation and amortization		11,298			11,791		(4%)
Gain on asset sales, net		(13	)		—		*
Total costs and expenses		16,965			20,857		(19%)
Add:
Depreciation and amortization		11,298			11,791
Adjustments related to MVC shortfall payments		223			(103	)
Adjustments related to capital reimbursement activity		(243	)		(112	)
Gain on asset sales, net		(13	)		—
Segment adjusted EBITDA	$	23,557		$	25,999		(9%)

*Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.4 million compared to the three months ended March 31, 2019, primarily reflecting:

•

a $4.7 million decrease in gathering services and related fees as a result of natural production declines.

•

a $2.4 million decrease in operation and maintenance expense primarily due to $1.2 million in lower compensation expense and a $0.4 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 March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		233		260	(10%)

Volume throughput decreased compared to the three months ended March 31, 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 March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	10,443		$	13,025		(20%)
Natural gas, NGLs and condensate sales		3,871			604		541%
Other revenues (1)		1,260			1,656		(24%)
Total revenues		15,574			15,285		2%
Costs and expenses:
Cost of natural gas and NGLs		1,947			—		*
Operation and maintenance		4,695			5,498		(15%)
General and administrative		378			228		66%
Depreciation and amortization		3,797			3,941		(4%)
Loss on asset sales, net		59			7		*
Long-lived asset impairment		4			10,220		*
Total costs and expenses		10,880			19,894		(45%)
Add:
Depreciation and amortization		4,032			4,330
Adjustments related to MVC shortfall payments		—			1,453
Adjustments related to capital reimbursement activity		(29	)		(27	)
Loss on asset sales, net		59			7
Long-lived asset impairment		4			10,220
Segment adjusted EBITDA	$	8,760		$	11,374		(23%)

*Not considered meaningful

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

Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.6 million compared to the three months ended March 31, 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 $1.7 million decrease in total revenues less cost of natural gas and NGLs which primarily reflects lower volume throughput.

Other items to note:

•

In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 5 to the unaudited condensed consolidated financial statements). The noncash impairment expense had no impact on segment adjusted EBITDA for the three months ended March 31, 2019.

•

Also impacting total revenues and cost of natural gas and NGLs for the three months ended March 31, 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 March 31,
	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		364		379	(4%)

Volume throughput decreased compared to the three months ended March 31, 2019 primarily due to natural production declines partially offset by additional drilling and completion activities in the third quarter of 2019.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended March 31,
	2020			2019			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,235		$	6,197		1%
Total revenues		6,235			6,197		1%
Costs and expenses:
Operation and maintenance		813			954		(15%)
General and administrative		93			92		1%
Depreciation and amortization		2,300			2,283		1%
Total costs and expenses		3,206			3,329		(4%)
Add:
Depreciation and amortization		2,300			2,283
Adjustments related to capital reimbursement activity		(9	)		(9	)
Segment adjusted EBITDA	$	5,320		$	5,142		3%

*Not considered meaningful

Three months ended March 31, 2020. Segment adjusted EBITDA increased $0.2 million compared to the three months ended March 31, 2019.

Corporate and Other Overview for the Three Months Ended March 31, 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, interest expense and a change in the Deferred Purchase Price Obligation fair value.

	Corporate and Other
	Three months ended March 31,
	2020		2019		Percentage Change
	(Dollars in thousands)
Revenues:
Total revenues		643		23,517	(97%)
Costs and expenses:
Cost of natural gas and NGLs		—		23,322	*
General and administrative		14,821		16,140	(8%)
Transaction costs		11		950	*
Interest expense		20,218		17,527	15%
Deferred Purchase Price Obligation		2,297		4,427	*

* 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 $22.9 million compared to the three months ended March 31, 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 $23.3 million compared to the three months ended March 31, 2019 was attributable to lower marketing activity.

General and Administrative. General and administrative expense decreased $1.3 million compared to the three months ended March 31, 2019 primarily due to a decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives.

Transaction costs. The decrease in transaction costs recognized during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to the financial advisory costs associated primarily with the Equity Restructuring that occurred in 2019.

Interest Expense. Interest expense increased $2.7 million compared to the three months ended March 31, 2019 primarily as a result of a higher average outstanding balance on the Revolving Credit Facility.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the three months ended March 31, 2019 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down (see Note 16 to the unaudited condensed consolidated financial statements).

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 9 to the unaudited condensed consolidated financial statements). 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 three months ended March 31, 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 March 31, 2020 and December 31, 2019 follow.

	March 31, 2020
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	4,897	$	150,601
Noncurrent assets		11,907		2,361,034

Liabilities
Current liabilities	$	11,002	$	66,375
Noncurrent liabilities		186,763		1,539,410

	December 31, 2019
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	2,311	$	109,664
Noncurrent assets		9,572		2,389,032

Liabilities
Current liabilities	$	9,662	$	73,877
Noncurrent liabilities		184,088		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 three months ended March 31, 2020 and for the year ended December 31, 2019 follow.

	Three months ended March 31, 2020
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	104,903
Total costs and expenses		951			78,990
(Loss) income before income taxes and income from equity method investees		(3,675	)		5,695
Income from equity method investees		—			3,762
Net (loss) income		(3,648	)		9,457

	Year ended December 31, 2019
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	443,528
Total costs and expenses		4,401			397,939
Loss before income taxes and loss from equity method investees		(1,968	)		(28,840	)
Loss from equity method investees (1)		—			(336,950	)
Net loss		(3,142	)		(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

On May 3, 2020, we suspended distributions to holders of our common units and suspended payment 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, preferred equity and equity securities and proceeds from potential asset divestitures.

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 weeks. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin and DJ Basin reportable segments, we now expect 2020 total capital expenditures to range from $30 million to $50 million.

We are currently in compliance with all covenants contained in our Revolving Credit Facility and Senior Notes, and at March 31, 2020, SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) were 5.05 to 1.0 and 2.26 to 1.0, respectively, relative to maximum threshold limits of 5.5x and 3.75x. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on access to capital markets 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.

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 during the three months ended March 31, 2020. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2019 Annual Report.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility that matures in May 2022. As of March 31, 2020, the outstanding balance of the Revolving Credit Facility was $698.0 million and the unused portion totaled $542.9 million, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of March 31, 2020 was approximately $120 million. There were no defaults or events of default during the three months ended March 31, 2020, and, as of March 31, 2020, we were in compliance with the financial covenants in the Revolving Credit Facility. See Notes 9 and 15 to the unaudited condensed consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $9.1 million letter of credit, respectively.

Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the three months ended March 31, 2020 on either series of senior notes.

For additional information on our long-term debt, see Note 9 to the unaudited condensed consolidated financial statements.

Deferred Purchase Price Obligation

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Note 16 to the unaudited condensed consolidated financial statements and the “Contractual Obligations Update” section below).

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:

	March 31,
	2020			2019
	(In thousands)
Net cash provided by operating activities	$	73,968		$	52,711
Net cash (used in) provided by investing activities		(76,399	)		28,493
Net cash provided by (used in) financing activities		41,842			(80,249	)
Net change in cash, cash equivalents and restricted cash	$	39,411		$	955

Operating activities. Cash flows from operating activities for the three months ended March 31, 2020 primarily reflected:

•

a $13.8 million increase in accounts receivable related to the timing of invoicing and cash collections;

•

a $3.7 million increase in accounts payable due to the timing of payment obligations;

•

a $2.8 million increase in deferred revenue for cash receipts not yet recognized as revenue;

•

a $1.3 million increase in cash interest payments; and

•

other changes in working capital.

Investing activities. Cash flows used in investing activities during the three months ended March 31, 2020 primarily reflected:

•

$58.0 million for investments in the Double E joint venture relating to the Double E Project; and

•

$18.6 million of capital expenditures primarily attributable to the DJ Basin of $6.3 million, the Williston Basin of $4.9 million and Summit Permian of $3.3 million.

Cash flows used in investing activities during the three months ended March 31, 2019 primarily reflected:

•

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

•

$60.8 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $28.4 million, Corporate and Other of $16.1 million (inclusive of capital expenditures of $15.8 million relating to the Double E Project), the Williston Basin of $8.0 million and Summit Permian of $7.1 million.

Financing activities. Cash flows used in financing activities during the three months ended March 31, 2020 primarily reflected:

•

$33.9 million of net proceeds from the issuance of Subsidiary Series A Preferred Units;

•

$21.0 million of net borrowings under our Revolving Credit Facility; and

•

$11.7 million of distributions.

Cash flows used in financing activities during the three months ended March 31, 2019 primarily reflected:

•

$45.3 million of distributions;

•

$32.0 million of net repayments under our Revolving Credit Facility.

Contractual Obligations Update

Deferred Purchase Price Obligation

In March 2016, we recognized the Deferred Purchase Price Obligation in connection with the 2016 Drop Down. Pursuant to the Equity Restructuring, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation.

As of March 31, 2020, the Remaining Consideration of the Deferred Purchase Price Obligation on the unaudited condensed consolidated balance sheet was $180.75 million.

For additional information, see Note 16 to the unaudited condensed consolidated financial statements.

Double E Project

Upon completion of the Double E Project, we expect to own at least a 50% interest in the Double E Project, will lead the development, permitting and construction of the Double E Project and will operate the pipeline upon 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 $350.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the required regulatory approvals (including the Federal Energy Regulatory Commission’s issuance of the certificate required for us to pursue the Double E Project) and no material delays in construction, we expect that the Double E Project will be placed into service in the third 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 three months ended March 31, 2020, cash paid for capital expenditures totaled $18.9 million (see Note 4 to the unaudited condensed consolidated financial statements) which included $5.1 million of maintenance capital expenditures. For the three months ended March 31, 2020, there were no contributions to Ohio Gathering and we contributed $58.0 million to Double E (see Note 8 to the unaudited condensed consolidated financial statements).

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 neutral to Summit. We are currently targeting a financing structure that limits cash investments by us during 2020, and which shifts a substantial majority of our Double E capital commitments to third parties. On December 24, 2019, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco to TPG for net proceeds of $27.3 million.

During the three months ended March 31, 2020, we issued an additional 35,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $34.4 million (after deducting underwriting discounts and offering expenses) to fund Summit’s share of capital expenses associated with the Double E Project.

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 customer, who was not meeting its MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.

For additional information, see Notes 4, 9, 11 and 16 to the unaudited condensed consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the three months ended March 31, 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, our subsidiaries, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.

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

•

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

•

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 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 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 or the Deferred Purchase Price Obligation, 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 of SMP Holdings to meet its 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 March 31, 2020, we had $800.0 million principal of fixed-rate Senior Notes and $698.0 million outstanding under our variable rate Revolving Credit Facility (see Note 9 to the unaudited condensed consolidated financial statements). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, 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, certain of which include MVCs and 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 March 31, 2020 and (ii) no change in internal control over financial reporting occurred during the quarter ended March 31, 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 15 to our unaudited condensed consolidated financial statements “Leases, 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 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. The risk factor presented below updates, and should be considered in addition to, the risk factors previously disclosed by us in Item 1A of the 2019 Annual Report.

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. 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, including new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. 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. 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, 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. 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 impasse in OPEC negotiations 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.

A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.

Various aspects of our operations are subject to regulation by the various federal, state and local departments and agencies that have jurisdiction over participants in the energy industry. The regulation of our activities and the natural gas and crude oil industries frequently change as they are reviewed by legislators and regulators. In 2016, the North Dakota Industrial Commission adopted rule changes that resulted in additional construction and monitoring requirements for certain underground gathering pipelines, including, but not limited to, those that transport produced water. The NDIC also adopted reclamation bonding requirements for certain underground gathering pipelines. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. In November 2018, PHMSA also increased the maximum penalties for violating federal safety standards, which are subject to future increases to account for inflation. In October 2019, PHMSA issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. In February 2020, PHMSA proposed changes to pipeline safety regulations that would require the installation of automatic shutoff valves, remote-control valves, or equivalent technology on all newly constructed or entirely replaced natural gas transmission and hazardous liquid pipelines that have nominal diameters of 6 inches or greater. The proposed rule would also establish standards for the identification of ruptures, initiation of pipeline shutdowns, segment isolation, and improving the effectiveness of emergency response. To the extent the proposed rule creates additional requirements for our pipelines, it could have a material adverse effect on our operations, operating and maintenance expenses and revenues.

In addition, the adoption of proposals for more stringent legislation, regulation or taxation of drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. For example, in 2018 the Colorado state ballot included a proposed 2,500 foot setback for oil and gas development from occupied structures and certain other areas. While the proposal did not pass, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the state’s oil and gas regulator from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive

requirements on oil and gas operations than those issued by the state. Similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both.

Item 6. Exhibits.

Exhibit number		Description
2.1		Purchase Agreement, dated May 3, 2020, by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-C (SMLP IP), LP, Energy Capital Partners II-C (Summit IP), LP, Energy Capital Partners II (Summit Co-Invest), LP and Summit Midstream Management, LLC, as contributors, SMP TopCo, LLC and SMLP Holdings, LLC, as sellers, Summit Midstream Partners, LP, as the acquiror, and, solely for certain purposes set forth therein, Summit Midstream Partners GP, LLC (Incorporated herein by reference to Exhibit 2.1 to SMLP's Current Report on Form 8-K dated May 5, 2020 (Commission File No. 001-35666))
3.1		Third Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of March 22, 2019 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated March 22, 2019 (Commission File No. 001-35666))
3.2		Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed October 4, 2012 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1	†	Summit Midstream Partners, LP 2012 Long-Term Incentive Plan, as amended and restated (incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated March 20, 2020 (Commission File No. 001-35666))
10.2	*	Form of Long-Term Incentive Plan Agreement for Employment Agreements
22.1	*	Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities
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.

† Management contract or compensatory plan or arrangement that is being filed as an exhibit pursuant to Item 9.01(d) of SMLP’s Form 8-K filed March 20, 2020 (Commission File No. 001-35666)

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

SIGNATURES

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

	Summit Midstream Partners, LP

	(Registrant)

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

May 8, 2020	/s/ Marc D. Stratton

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