SEC Filing | Summit Midstream Corporation

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smlp-20210630

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 June 30, 2021


☐			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)

910 Louisiana Street, Suite 4200

Houston, TX

(Address of principal executive offices)

45-5200503

(I.R.S. Employer

Identification No.)

77002

(Zip Code)

(832) 413-4770

(Registrant’s telephone number, including area code)

Not applicable

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

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


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o 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).


x			Yes			o			No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer	☐	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. o

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

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


Class						As of August 1, 2021
Common Units						6,744,926 units

Table of Contents

TABLE OF CONTENTS


COMMONLY USED OR DEFINED TERMS		2

PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets.	5
	Unaudited Condensed Consolidated Statements of Operations.	6
	Unaudited Condensed Consolidated Statements of Partners' Capital.	7
	Unaudited Condensed Consolidated Statements of Cash Flows.	9
	Notes to Unaudited Condensed Consolidated Financial Statements.	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	46
Item 4.	Controls and Procedures.	46
PART II	OTHER INFORMATION	47
Item 1.	Legal Proceedings.	47
Item 1A.	Risk Factors.	47
Item 5.	Other Information.	48
Item 6.	Exhibits.	49

SIGNATURES		51

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COMMONLY USED OR DEFINED TERMS



2022 Senior Notes			Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
2025 Senior Notes			Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025

ASU			Accounting Standards Update
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

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

Epping			Epping Transmission Company, LLC
EPU			earnings or loss per unit
FASB			Financial Accounting Standards Board
Finance Corp.			Summit Midstream Finance Corp.
GAAP			accounting principles generally accepted in the United States of America
General Partner			Summit Midstream GP, LLC
GP			general partner
Grand River			Grand River Gathering, LLC
Guarantor Subsidiaries			Bison Midstream and its subsidiaries, Grand River and its subsidiaries, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, OpCo, Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer Midstream
hub			geographic location of a storage facility and multiple pipeline interconnections
LIBOR			London Interbank Offered Rate
Mbbl/d			one thousand barrels per day
Meadowlark Midstream			Meadowlark Midstream Company, LLC
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
NYSE			New York Stock Exchange
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

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Permian Holdco			Summit Permian Transmission Holdco, LLC
Permian Transmission Credit Facility			Credit Agreement, dated as of March 8, 2021, among Summit Permian Transmission, LLC, as borrower, MUFG Bank Ltd., as administrative agent, Mizuho Bank (USA), as collateral agent, ING Capital LLC, Mizuho Bank, Ltd. and MUFG Union Bank, N.A., as L/C issuers, coordinating lead arrangers and joint bookrunners, and the lenders from time to time party thereto
Polar and Divide			the Polar and Divide system; collectively Polar Midstream and Epping
produced water			water from underground geologic formations that is a by-product of natural gas and crude oil production
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, the Third Amendment to Third Amended and Restated Credit Agreement dated as of December 24, 2019 and the Fourth Amendment to Third Amended and Restated Credit Agreement dated as of December 18, 2020
SEC			Securities and Exchange Commission
segment adjusted EBITDA			total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit- based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains
Senior Notes			The 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 LTIP			SMLP Long-Term Incentive Plan
SMP Holdings			Summit Midstream Partners Holdings, LLC, also known as SMPH
SMPH Term Loan			the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings, as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent
Subsidiary Series A Preferred Units			Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco
Summit Holdings			Summit Midstream Holdings, LLC
Summit Investments			Summit Midstream Partners, LLC
Summit Marketing			Summit Midstream Marketing, LLC
Summit Permian			Summit Midstream Permian, LLC
Summit Permian II			Summit Midstream Permian II, LLC
Summit Permian Transmission			Summit Permian Transmission, LLC
Summit Utica			Summit Midstream Utica, LLC
the Partnership			Summit Midstream Partners, LP and its subsidiaries
the Partnership Agreement			the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership dated May 28, 2020
throughput volume			the volume of natural gas, crude oil or produced water gathered, transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput

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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

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2021		December 31, 2020
	(In thousands, except unit amounts)
ASSETS
Cash and cash equivalents	$	7,211	$	15,544
Restricted cash	314		—
Accounts receivable, net	61,233		61,932
Other current assets	11,090		4,623
Total current assets	79,848		82,099
Property, plant and equipment, net	1,768,897		1,817,546
Intangible assets, net	186,525		199,566
Investment in equity method investees	433,440		392,740
Other noncurrent assets	5,335		7,866
TOTAL ASSETS	$	2,474,045	$	2,499,817

LIABILITIES AND CAPITAL
Trade accounts payable	$	14,824	$	11,878
Accrued expenses	10,092		13,036
Deferred revenue	10,593		9,988
Ad valorem taxes payable	5,395		9,086
Accrued compensation and employee benefits	5,847		9,658
Accrued interest	8,007		8,007
Accrued environmental remediation	1,959		1,392
Current portion of long-term debt	762,000		—
Other current liabilities	28,209		5,363
Total current liabilities	846,926		68,408
Long-term debt, excluding current portion	539,099		1,347,326
Noncurrent deferred revenue	44,857		48,250
Noncurrent accrued environmental remediation	1,192		1,537
Other noncurrent liabilities	38,994		21,747
Total liabilities	1,471,068		1,487,268
Commitments and contingencies (Note 13)

Mezzanine Capital
Subsidiary Series A Preferred Units (88,321 and 85,308 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)	97,679		89,658

Partners' Capital
Series A Preferred Units (143,447 and 162,109 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)	161,907		174,425
Common limited partner capital (6,744,926 and 6,110,092 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)	743,391		748,466
Total partners' capital	905,298		922,891
TOTAL LIABILITIES AND CAPITAL	$	2,474,045	$	2,499,817

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	74,233	$	73,911	$	144,580	$	157,703
Natural gas, NGLs and condensate sales	16,416		10,683		37,180		24,463
Other revenues	9,392		7,413		17,599		14,744
Total revenues	100,041		92,007		199,359		196,910
Costs and expenses:
Cost of natural gas and NGLs	16,626		6,088		37,102		14,313
Operation and maintenance	17,507		21,152		34,100		42,963
General and administrative	29,360		12,786		39,938		29,347
Depreciation and amortization	28,364		29,630		56,875		59,296
Transaction costs	450		1,207		217		1,218
Gain on asset sales, net	(4)		(281)		(140)		(166)
Long-lived asset impairments	33		654		1,525		4,475
Total costs and expenses	92,336		71,236		169,617		151,446
Other income (expense), net	(2,334)		276		(2,284)		(151)
Loss on ECP Warrants	(12,159)		—		(13,634)		—
Interest expense	(15,502)		(21,990)		(29,455)		(45,818)
Gain on early extinguishment of debt	—		54,235		—		54,235
Income (loss) before income taxes and equity method investment income	(22,290)		53,292		(15,631)		53,730
Income tax benefit	248		389		262		402
Income from equity method investees	2,304		3,040		4,619		6,351
Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483
Net income attributable to Subsidiary Series A Preferred Units	(4,089)		(1,397)		(8,021)		(2,342)
Net loss attributable to noncontrolling interest	—		1,393		—		3,274
Net income (loss) attributable to Summit Midstream Partners, LP	$	(23,827)	$	56,717	$	(18,771)	$	61,415
Less: net income attributable to Series A Preferred Units	(3,849)		(7,125)		(8,136)		(14,250)
Add: deemed contribution from 2021 Preferred Exchange Offer	8,326		—		8,326		—
Net income (loss) attributable to common limited partners	$	(19,350)	$	49,592	$	(18,581)	$	47,165
Net income (loss) per limited partner unit:
Common unit – basic	$	(2.91)	$	16.66	$	(2.91)	$	15.73
Common unit – diluted	$	(2.91)	$	15.92	$	(2.91)	$	15.27

Weighted-average limited partner units outstanding:
Common units – basic	6,656		2,977		6,392		2,999
Common units – diluted	6,656		3,116		6,392		3,088

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL


	Noncontrolling Interest				Partners' Capital
	Series A Preferred Units		Common Noncontrolling Interests		Series A Preferred Units		Partners' Capital		Total
	(In thousands)
Partners' capital, January 1, 2021	$	—	$	—	$	174,425	$	748,466	$	922,891
Net income	—		—		4,287		769		5,056
Unit-based compensation	—		—		—		1,967		1,967
Tax withholdings and associated payments on vested SMLP LTIP awards	—		—		—		(1,274)		(1,274)
Partners' capital, March 31, 2021	—		—		178,712		749,928		928,640
Net income (loss)	—		—		3,849		(27,676)		(23,827)
Unit-based compensation	—		—		—		1,048		1,048
Tax withholdings and associated payments on vested SMLP LTIP awards	—		—		—		(98)		(98)
Tax withholdings on 2021 Preferred Exchange Offer	—		—		—		(465)		(465)
Effect of 2021 Preferred Exchange Offer, inclusive of an $8.3 million deemed contribution to common unit holders (Note 9)	—		—		(20,654)		20,654		—
Partners' capital, June 30, 2021	$	—	$	—	$	161,907	$	743,391	$	905,298

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

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2021		2020
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(10,750)	$	60,483
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	57,344		59,766
Noncash lease expense	519		1,557
Amortization of debt issuance costs	3,447		3,136
Unit-based and noncash compensation	3,015		4,569
Income from equity method investees	(4,619)		(6,351)
Distributions from equity method investees	13,116		12,749
Gain on asset sales, net	(140)		(166)
Loss on ECP Warrants	13,634		—
Unsettled loss on interest rate swaps	2,692		—
Gain on extinguishment of debt	—		(54,235)
Long-lived asset impairment	1,525		4,475
Changes in operating assets and liabilities:
Accounts receivable	(1,993)		20,219
Trade accounts payable	2,989		1,411
Accrued expenses	(3,127)		(8)
Deferred revenue, net	(2,787)		5,500
Ad valorem taxes payable	(3,691)		(2,170)
Accrued interest	—		(609)
Accrued environmental remediation, net	(512)		(545)
Other, net	15,555		(4,410)
Net cash provided by operating activities	86,217		105,371
Cash flows from investing activities:
Capital expenditures	(5,962)		(27,426)
Proceeds from asset sale	8,000		—
Investment in Double E equity method investee	(48,943)		(79,728)
Other, net	—		217
Net cash used in investing activities	(46,905)		(106,937)
Cash flows from financing activities:
Net cash distributions to noncontrolling interest SMLP unitholders	—		(6,037)
Borrowings under Revolving Credit Facility	—		90,000
Repayments on Revolving Credit Facility	(95,000)		(34,000)
Borrowings under Permian Transmission Credit Facility	53,500		—
Repayments on SMPH Term Loan	—		(6,300)

Repurchase of Senior Notes	—		(76,707)
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs	—		48,710
Borrowings under ECP Loans	—		35,000
Purchase of common units in GP Buy-In Transaction	—		(41,778)
Debt issuance costs	(5,179)		(1,080)
Proceeds from asset sale	260		288
Other, net	(912)		(1,833)
Net cash provided by (used in) financing activities	(47,331)		6,263
Net change in cash, cash equivalents and restricted cash	(8,019)		4,697
Cash, cash equivalents and restricted cash, beginning of period	15,544		36,922
Cash, cash equivalents and restricted cash, end of period	$	7,525	$	41,619

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

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. Summit Midstream Partners, LP (including its subsidiaries, collectively “SMLP” or the “Partnership”) is a Delaware limited partnership that 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. The Partnership’s business activities are primarily conducted through various operating subsidiaries, each of which is owned or controlled by its wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company.

GP Buy-In Transaction. On May 28, 2020, the Partnership closed the transactions contemplated by the Purchase Agreement (the “Purchase Agreement”), dated May 3, 2020, with affiliates of its sponsor at that time, Energy Capital Partners II, LLC (“ECP”), to acquire Summit Investments, the parent company of the General Partner. The acquisition of Summit Investments resulted in the Partnership acquiring (a) 2.3 million SMLP common units (34.6 million SMLP common units prior to the Partnership’s 1-for-15 reverse unit split of its common units, effective November 9, 2020 (the “Reverse Unit Split”)) that were pledged as collateral under the SMPH Term Loan, (b) 0.7 million SMLP common units (10.7 million SMLP common units prior to the Reverse Unit Split) that were not pledged as collateral under the SMPH Term Loan and (c) a deferred purchase price obligation receivable owed by the Partnership. In addition, the Partnership acquired 0.4 million SMLP common units held by an affiliate of ECP (5.7 million SMLP common units prior to the Reverse Unit Split). The total purchase price was $35.0 million in cash and warrants giving ECP the right to purchase up to 0.7 million SMLP common units (10.0 million SMLP common units prior to the Reverse Unit Split) (refer to Note 9 – Partners’ Capital and Mezzanine Capital for additional details). Pursuant to the Purchase Agreement, the Partnership assumed the liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream, a subsidiary of the Partnership, that occurred near Williston, North Dakota and was discovered on January 6, 2015. These transactions are collectively referred to as the “GP Buy-In Transaction.”

As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner. Following the closing of the GP Buy-In Transaction, the Partnership retired 1.1 million SMLP common units (16.6 million common units prior to the Reverse Unit Split) it acquired that were not pledged as collateral under the SMPH Term Loan. On November 17, 2020, the Partnership issued the 2.3 million SMLP common units (34.6 million common units prior to the Reverse Unit Split) that were pledged as collateral under the SMPH Term Loan as partial consideration for a consensual debt discharge and restructuring (the “TL Restructuring”) of its SMP Holdings’ $155.2 million term loan (“SMPH Term Loan”). SMP Holdings is a wholly-owned subsidiary of Summit Investments.

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

Business Operations. The Partnership provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. The Partnership’s results are primarily driven by the volumes of natural gas that it gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers. Other than the Partnership’s investments in Double E and Ohio Gathering, all of its business activities are conducted through wholly owned operating subsidiaries.

Presentation and Consolidation. The Partnership prepares its condensed consolidated financial statements in accordance with GAAP as established by the FASB and pursuant to the rules and regulations of the SEC pertaining to interim financial information. The condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. These unaudited condensed consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and related notes that are included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020.

The Partnership makes 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. Although management believes these estimates are reasonable, actual results could differ from its estimates.

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The condensed consolidated financial statements contained in this report include the assets, liabilities and results of operations of SMLP and its subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. Comprehensive income or loss is the same as net income or loss for all periods presented.

Risks and Uncertainties. The Partnership continues to closely monitor the impact of the COVID-19 pandemic on all aspects of its business, including how it has impacted and will impact its customers, employees, supply chain and distribution network. The Partnership is unable to predict the ultimate impact that COVID-19 may have on its business, future results of operations, financial position or cash flows.

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

Going Concern Assessment. The accompanying unaudited condensed consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The Partnership’s wholly owned subsidiary, Summit Holdings, has a senior secured revolving credit facility due May 13, 2022 (the “Revolving Credit Facility”). As a result of this maturity date being within 12 months after the date that these financial statements were issued, the amounts due on the Revolving Credit Facility have been included in the Partnership’s going concern assessment. A lack of sufficient available liquidity to repay the Revolving Credit Facility balance at maturity, which would be a nonpayment event that would also cause a cross-default under the Partnership's other outstanding indebtedness, over the next 12 months has raised substantial doubt about the Partnership’s ability to continue as a going concern.

The Partnership is in the process of arranging new financing, which may include a new 4.5-year asset-based revolving credit facility (the “ABL Revolver”) that is expected to (i) have a borrowing capacity of $400.0 million to $500.0 million and (ii) conditioned on the successful arrangement of a $700.0 million to $750.0 million offering of high yield notes (the “High Yield Notes Offering”). The ABL Revolver and the High Yield Notes Offering are expected to close concurrently prior to September 30, 2021, and collectively, the proceeds will be used to refinance the Revolving Credit Facility and redeem the senior unsecured notes due August 15, 2022 (the "2022 Senior Notes") of Summit Holdings and Finance Corp., another of the Partnership's wholly-owned subsidiaries. There is no assurance that additional financing will be available when needed or that the Partnership will be able to obtain financing on acceptable terms.

The unaudited condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

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

Except for the below, there have been no changes to the Partnership’s significant accounting policies since December 31, 2020.

Cash, Cash Equivalents and Restricted Cash. The Partnership considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash that is held by a major bank and has restrictions on its availability to the Partnership is classified as restricted cash. The restricted cash balance of $0.3 million at June 30, 2021 is related to proceeds from the Permian Transmission Credit Facility, which is available to finance Permian Transmission’s capital calls associated with its investment in Double E, for debt service or other general corporate purposes. See Note 7 - Debt for additional information.

Interest Rate Swaps. Interest rate swap agreements are reported as either assets or liabilities on the consolidated balance sheet at fair value. Interest rate swap agreements are not designated as cash-flow hedges, and accordingly, the changes in the fair value are recorded in earnings. The Partnership does not use interest rate swap agreements for speculative purposes.

New accounting standards recently implemented.

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

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disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures.

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

New accounting standards not yet implemented.

ASU No. 2020-6 Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815 – 40) (“ASU 2020-6”). ASU 2020-6 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The Partnership is currently evaluating the provisions of ASU 2020-6 to determine its impact on the Partnership’s consolidated financial statements and disclosures.

ASU No. 2020-4 Reference Rate Reform (“ASU 2020-4”). ASU 2020-4 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 2020-4 are effective as of March 12, 2020 through December 31, 2022. The Partnership is currently evaluating the provisions of ASU 2020-4 to determine its impact on the Partnership’s consolidated financial statements and disclosures.

3. REVENUE

Performance obligations. The following table presents estimated revenue expected to be recognized during the remainder of 2021 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated minimum volume commitments.


	2021		2022		2023		2024		2025		Thereafter

Gathering services and related fees	$	46,183	$	80,064	$	62,179	$	51,645	$	35,200	$	21,433

Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. For more detailed information about reportable segments, see Note 15 – Segment Information.


	Three Months Ended June 30, 2021
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	11,349	$	—	$	—	$	11,349
Williston Basin	12,516		8,201		4,242		24,959
DJ Basin	5,891		305		1,856		8,052
Permian Basin	2,262		6,875		121		9,258
Piceance Basin	25,527		1,025		1,233		27,785
Barnett Shale	10,076		10		1,012		11,098
Marcellus Shale	6,612		—		—		6,612
Total reportable segments	74,233		16,416		8,464		99,113
Corporate and Other	—		—		928		928
Total	$	74,233	$	16,416	$	9,392	$	100,041

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	Six Months Ended June 30, 2021
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	19,920	$	—	$	—	$	19,920
Williston Basin	25,149		20,428		8,749		54,326
DJ Basin	12,154		415		2,560		15,129
Permian Basin	4,461		13,393		237		18,091
Piceance Basin	50,311		2,878		2,409		55,598
Barnett Shale	19,772		66		2,072		21,910
Marcellus Shale	12,813		—		—		12,813
Total reportable segments	144,580		37,180		16,027		197,787
Corporate and Other	—		—		1,572		1,572
Total	$	144,580	$	37,180	$	17,599	$	199,359


	Three Months Ended June 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	11,538	$	—	$	—	$	11,538
Williston Basin	12,407		3,131		2,776		18,314
DJ Basin	5,228		71		993		6,292
Permian Basin	2,711		4,222		126		7,059
Piceance Basin	26,222		401		1,096		27,719
Barnett Shale	9,877		2,858		1,778		14,513
Marcellus Shale	5,928		—		—		5,928
Total reportable segments	73,911		10,683		6,769		91,363
Corporate and Other	—		—		644		644
Total	$	73,911	$	10,683	$	7,413	$	92,007


	Six Months Ended June 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	18,500	$	—	$	—	$	18,500
Williston Basin	36,204		7,455		5,918		49,577
DJ Basin	12,083		141		2,027		14,251
Permian Basin	5,022		8,734		313		14,069
Piceance Basin	53,411		1,404		2,161		56,976
Barnett Shale	20,320		6,729		3,038		30,087
Marcellus Shale	12,163		—		—		12,163
Total reportable segments	157,703		24,463		13,457		195,623
Corporate and Other	—		—		1,287		1,287
Total	$	157,703	$	24,463	$	14,744	$	196,910

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Contract balances. Contract assets relate to the Partnership’s rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from its 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:


	2021
	(In thousands)
Contract assets, January 1,	$	2,026
Additions	4,985
Transfers out	(973)
Contract assets, June 30,	$	6,038

As of June 30, 2021, receivables with customers totaled $54.3 million and contract assets totaled $6.0 million and were included in the accounts receivable caption on the unaudited condensed consolidated balance sheets.

As of December 31, 2020, receivables with customers totaled $57.5 million and contract assets totaled $2.0 million which were included in the accounts receivable caption on the unaudited condensed consolidated balance sheets.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. The Partnership recognizes contract liabilities under these arrangements in revenue over the contract period. For the three months ended June 30, 2021 and 2020, the Partnership recognized $2.1 million and $2.3 million of gathering services and related fees, respectively, which were included in the contract liability balance as of the beginning of the period. For the six months ended June 30, 2021 and 2020, the Partnership recognized $3.3 million and $4.7 million of gathering services and related fees, respectively, which were included in the contract liability balance as of the beginning of the period. See Note 6 – Deferred Revenue for additional details.

4. PROPERTY, PLANT AND EQUIPMENT

Details of the Partnership’s property, plant and equipment follows.


	June 30, 2021		December 31, 2020
	(In thousands)
Gathering and processing systems and related equipment	$	2,221,834	$	2,213,501
Construction in progress	45,780		60,443
Land and line fill	10,440		10,440
Other	59,683		61,340
Total	2,337,737		2,345,724
Less: accumulated depreciation	(568,840)		(528,178)
Property, plant and equipment, net	$	1,768,897	$	1,817,546

Depreciation expense and capitalized interest for the Partnership follows.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)
Depreciation expense	$	21,318	$	21,664	$	42,784	$	43,362
Capitalized interest	149		328		324		820

5. EQUITY METHOD INVESTMENTS

Double E. The Partnership is responsible for leading the development, permitting and construction of the Double E Project. During the six month periods ended June 30, 2021 and 2020, the Partnership made cash investments of $48.9 million and $79.7 million, respectively, in the Double E Project which included $1.6 million and $0.3 million of capitalized interest respectively. Other than the investment activity noted above, Double E did not have any results of operations for the six months ended June 30, 2021, given that the Double E Project is currently under development.

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Ohio Gathering. As of June 30, 2021 and December 31, 2020, the Partnership’s ownership interest in Ohio Gathering was 38.0% and 38.2%, respectively. A reconciliation of the difference between the carrying amount of the Partnership’s interest in Ohio Gathering and the Partnership’s underlying investment per Ohio Gathering's books and records is provided in the table below as of June 30, 2021.


	2021
	(In thousands)
Investment in Ohio Gathering, June 30,	$	252,537
June cash distributions	2,314
Basis difference	212,259
Investment in Ohio Gathering (Books and records), May 30,	$	467,110

6. DEFERRED REVENUE

Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped and/or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering or processing fee.

Many of the Partnership’s gas gathering agreements contain provisions that can reduce or delay the cash flows that it expects to receive from MVCs to the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period.

A rollforward of current deferred revenue follows.


	Total
	(In thousands)
Current deferred revenue, January 1, 2021	$	9,988
Add: additions	4,074
Less: revenue recognized	(3,469)
Current deferred revenue, June 30, 2021	$	10,593

A rollforward of noncurrent deferred revenue follows.


	Total
	(In thousands)
Noncurrent deferred revenue, January 1, 2021	$	48,250
Add: additions	667
Less: reclassification to current deferred revenue	(4,060)
Noncurrent deferred revenue, June 30, 2021	$	44,857

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7. DEBT

Debt for the Partnership at June 30, 2021 and December 31, 2020, follows:


	June 30, 2021		December 31, 2020
	(In thousands)
Revolving Credit Facility: Summit Holdings' variable rate senior secured revolving credit facility due May 13, 2022	$	762,000	$	857,000
Permian Transmission Credit Facility: Permian Transmission's variable rate senior secured credit facility due March 8, 2028	53,500		—
Less: unamortized debt issuance costs	(5,128)		—
2022 Senior Notes: Summit Holdings' 5.5% senior unsecured notes due August 15, 2022	234,047		234,047
Less: unamortized debt issuance costs	(630)		(859)
2025 Senior Notes: Summit Holdings' 5.75% senior unsecured notes due April 15, 2025	259,463		259,463
Less: unamortized debt issuance costs	(2,153)		(2,325)
Total debt	1,301,099		1,347,326
Less current maturities of:
Revolving Credit Facility	762,000		—

Total long-term debt	$	539,099	$	1,347,326

Revolving Credit Facility. The Partnership’s wholly owned subsidiary, Summit Holdings, has a Revolving Credit Facility which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has $1.1 billion of borrowing capacity and matures on May 13, 2022. At June 30, 2021, the applicable margin under LIBOR borrowings was 3.25%, the interest rate was 3.36% and the unused portion of the Revolving Credit Facility totaled $314.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance of $23.1 million in outstanding but undrawn irrevocable standby letters of credit. Based on covenant limits, the Partnership’s available borrowing capacity under the Revolving Credit Facility as of June 30, 2021 was approximately $137.6 million.

The Revolving Credit Facility includes three financial performance covenants which require Summit Holdings to maintain (i) a ratio of consolidated trailing 12-month earnings before interest, income taxes, depreciation and amortization (“EBITDA”) to net interest expense of not less than 2.50 to 1.00, as defined in the credit agreement, (ii) a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.75 to 1.00 and (iii) a ratio of first lien net indebtedness to consolidated trailing 12-month EBITDA of not more than 3.50 to 1.00. As of and during the six months ended June 30, 2021, the Partnership was in compliance with the Revolving Credit Facility's financial covenants, including the financial performance covenants, and there were no defaults or events of default.

Permian Transmission Credit Facility. On March 8, 2021 (the “Closing Date”), the Partnership’s unrestricted subsidiary, Permian Transmission, entered into a Credit Agreement which allows for $175.0 million of senior secured credit facilities (the “Permian Transmission Credit Facilities”), including a $160.0 million Term Loan Facility and a $15.0 million Working Capital Facility. The Permian Transmission Credit Facilities can be used to finance Permian Transmission’s capital calls associated with its investment in Double E, debt service and other general corporate purposes. Unexpended proceeds from draws on the Permian Transmission Credit Facilities are classified as restricted cash on the accompanying unaudited condensed consolidated balance sheets.

As of June 30, 2021, the applicable margin under Adjusted LIBOR borrowings was 2.375%, the interest rate was 2.5% and the unused portion of the Permian Transmission Credit Facilities totaled $121.5 million, subject to a commitment fee of 0.70% as of June 30, 2021. Based on covenant limits, the Partnership’s available borrowing capacity under the Permian Transmission Credit Facilities, as of June 30, 2021, was approximately $119.5 million. As of and during the period from the Closing Date to June 30, 2021, the Partnership was in compliance with the Permian Transmission Credit Facilities financial covenants. There were no defaults or events of default during the period from the Closing Date to June 30, 2021.

2022 Senior Notes. The 2022 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior, unsecured obligations. The 2022 Senior Notes are effectively subordinated in right of payment to all secured indebtedness, to the extent of the collateral securing such indebtedness.

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Summit Holdings and Finance Corp., the co-issuers of the 2022 Senior Notes (the “Co-Issuers”) may redeem all or part of the 2022 Senior Notes at a redemption price of 100.00%, plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 2022 Senior Notes.

As of and during the six month period ended June 30, 2021, that Partnership was in compliance with the financial covenants governing its 2022 Senior Notes.

2025 Senior Notes. The 2025 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of the Partnership’s existing and future senior unsecured obligations. The 2025 Senior Notes are effectively subordinated in right of payment to all of the Partnership’s secured indebtedness, to the extent of the collateral securing such indebtedness.

As of June 30, 2021, the Co-Issuers have the right to redeem all or part of the 2025 Senior Notes at a redemption price of 102.875% (with the redemption price declining ratably each year to 100.000% on April 15, 2023), plus accrued and unpaid interest, if any, to, but not including the redemption date. Debt issuance costs of $7.7 million are being amortized over the life of the 2025 Senior Notes.

As of and during the six month period ended June 30, 2021, that Partnership was in compliance with the financial covenants governing its 2025 Senior Notes.

Gain on Extinguishment of Debt. The Partnership had less than $0.1 million of gain on extinguishment of debt for the six months ended June 30, 2021. The Partnership recognized a $54.2 million gain on extinguishment of debt during the six months ended June 30, 2020, as the result of open market repurchases of its Senior Notes.


	Open Market Repurchases During the Six Months Ended June 30, 2020				Total
	2022		2025
	Senior Notes		Senior Notes
Gain on repurchases of Senior Notes	$	9,300	$	46,003		$	55,303
Debt issue costs	(117)		(951)			(1,068)

Gain on extinguishment	$	9,183	$	45,052		$	54,235

8. FINANCIAL INSTRUMENTS

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


	June 30, 2021				December 31, 2020
	Carrying Value, Net		Estimated fair value (Level 2)		Carrying Value, Net		Estimated fair value (Level 2)
	(In thousands)
2022 Senior Notes	$	233,417	$	229,171	$	233,188	$	215,713
2025 Senior Notes	257,310		237,625		257,138		168,002

The balance sheet carrying values for the Revolving Credit Facility and the Permian Transmission Credit Facility represent fair value due to their floating interest rates. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of June 30, 2021 and December 31, 2020. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

Interest Rate Swaps. In connection with the Permian Transmission Credit Facility, the Partnership entered into $161.5 million of notional amount interest rate swaps to manage its exposure to variability in expected cash flows attributable to interest rate risk. Interest rate swaps convert a portion of the Partnership’s variable rate debt to fixed rate debt. The Partnership chooses counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Partnership actively monitors the creditworthiness where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Partnership. The Partnership presents its derivative positions on a gross basis and does not net the asset and liability positions.

As of June 30, 2021, the Partnership’s interest rate swap agreements had a fair value of $2.7 million and are recorded within other current liabilities and other noncurrent liabilities within the unaudited condensed consolidated balance sheets.

9. PARTNERS' CAPITAL AND MEZZANINE CAPITAL

Common Units. A rollforward of the number of issued and outstanding common limited partner units follows for the period from December 31, 2020 to June 30, 2021.

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			Common Units
Units, December 31, 2020			6,110,092
2021 Preferred Exchange Offer, net of shares withheld for taxes			538,715
Common units issued for SMLP LTIP, net			96,119
Units, June 30, 2021			6,744,926

Series A Preferred Units. In 2017, the Partnership issued 300,000 Series A Preferred Units at a price to the public of $1,000 per unit. As of June 30, 2021, the Partnership had 143,447 Series A Preferred Units outstanding and $22.1 million of accrued and unpaid distributions on its Series A Preferred Units.

Series A Preferred Unit Exchange Offer. In April 2020, the Partnership completed an offer to exchange its Series A Preferred Units for newly issued common units, whereby it issued 538,715 SMLP common units, net of units withheld for withholding taxes, in exchange for 18,662 Series A Preferred Units.

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

During the six months ended June 30, 2021, the Partnership elected to make PIK distributions and issued 3,013 Subsidiary Series A Preferred Units to the holders of its Subsidiary Series A Preferred Units. As of June 30, 2021, the Partnership has 88,321 Subsidiary Series A Preferred Units issued and outstanding.

If the Subsidiary Series A Preferred Units were redeemed on June 30, 2021, the redemption amount would be $110.4 million when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Subsidiary Series A Preferred Unit agreement.

The following table shows the change in our Subsidiary Series A Preferred Unit balance from January 1, 2021 to June 30, 2021:


	2021
	(in thousands)
Balance at January 1,	$	89,658
PIK distributions	3,013
Redemption accretion	5,008
Balance at June 30,	$	97,679

Warrants. On May 28, 2020, and in connection with the GP Buy-In Transaction, the Partnership issued (i) a warrant to purchase up to 537,307 SMLP common units (8,059,609 SMLP common units prior to the Reverse Unit Split) to SMP TopCo, LLC, a Delaware limited liability company and affiliate of ECP (“ECP NewCo”) (the “ECP NewCo Warrant”), and (ii) a warrant to purchase up to 129,360 SMLP common units (1,940,391 SMLP common units prior to the Reverse Unit Split) to SMLP Holdings, LLC, a Delaware limited liability company and affiliate of ECP (“ECP Holdings” and together with ECP NewCo, the "ECP Entities") (the “ECP Holdings Warrant” and together with the ECP NewCo Warrant, the “ECP Warrants”). The exercise price under the ECP Warrants is $15.345 per SMLP common unit ($1.025 prior to the Reverse Unit Split) and upon exercising the ECP Warrants, the Partnership may issue a maximum of 666,667 SMLP common units (10,000,000 SMLP common units prior to the Reverse Unit Split) under the ECP Warrants.

Upon exercise of the ECP Warrants, each of ECP NewCo and ECP Holdings may receive, at its election: (i) a number of SMLP common units equal to the number of SMLP common units for which the ECP Warrants are being exercised, if exercising the ECP Warrants by cash payment of the exercise price; (ii) a number of SMLP common units equal to the product of the number of common units being exercised multiplied by (a) the difference between the average of the daily volume-weighted average price (“VWAP”) of the SMLP common units on the NYSE on each of the three trading days prior to the delivery of the notice of exercise (the “VWAP Average”) and the exercise price (the “VWAP Difference”), divided by (b) the VWAP Average; and/or (iii) an amount in cash, to the extent that the payment of such cash would not result in any violation of any financial covenant under the Revolving Credit Facility, and the Partnership’s leverage ratio would be at least 0.5x less than the maximum applicable ratio set forth in the Revolving Credit Facility, equal to the product of (a) the number of SMLP common units exercised and (b) the VWAP Difference, subject to certain adjustments under the ECP Warrants.

The ECP Warrants are subject to standard anti-dilution adjustments for stock dividends, stock splits (including reverse splits) and recapitalizations and are exercisable at any time on or before May 28, 2023. Upon exercise of the ECP Warrants, the

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proceeds to the holders of the ECP Warrants, whether in the form of cash or common units, will be capped at $30.00 ($2.00 prior to the Reverse Unit Split) per SMLP common unit above the exercise price.

On August 5, 2021, the ECP Entities cashlessly exercised all of the ECP Warrants for an aggregate of 414,447 SMLP common units, net of the exercise price, as calculated pursuant to Section 3(c) of the ECP Warrants. The Partnership has delivered instructions to American Stock Transfer & Trust Company, LLC, its transfer agent, to issue these SMLP common units to the ECP Entities.

At June 30, 2021, the ECP Warrants were valued at $15.5 million, were accounted for as a liability instrument and recorded within other current liabilities on the unaudited condensed consolidated balance sheets. The value as of June 30, 2021 approximates the settlement value on August 5, 2021, the date in which the ECP Warrants were exercised by their holders. See Note 16 - Subsequent Events for further details.

Cash Distribution Policy. In connection with the GP Buy-In Transaction, the Partnership suspended its cash distributions to holders of its common units, commencing with respect to the quarter ending March 31, 2020. Upon the resumption of distributions, the Partnership Agreement requires that it distribute all available cash, subject to reserves established by its General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under this policy is subject to fluctuations based on the amount of cash the Partnership generates from its business and the decision to make any distribution is determined by the General Partner, taking into consideration the terms of the Partnership Agreement. The Partnership’s last distribution was paid on February 14, 2020, to unitholders of record at the close of business on February 7, 2020.

10. EARNINGS PER UNIT

The following table details the components of EPU.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands, except per-unit amounts)				(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net income (loss) among limited partner interests:
Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483
Net income attributable to Subsidiary Series A Preferred Units	(4,089)		(1,397)		(8,021)		(2,342)
Net loss attributable to noncontrolling interest	—		1,393		—		3,274
Net income (loss) attributable to Summit Midstream Partners, LP	(23,827)		56,717		(18,771)		61,415

Less: Net income attributable to Series A Preferred Units	(3,849)		(7,125)		(8,136)		(14,250)
Add: Deemed capital contribution from 2021 Preferred Exchange Offer	8,326		—		8,326		—
Net income (loss) attributable to common limited partners	(19,350)		$	49,592	(18,581)		$	47,165

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic	6,656		2,977		6,392		2,999
Effect of nonvested phantom units	—		139		—		89
Weighted-average common units outstanding – diluted	6,656		3,116		6,392		3,088

Net Income (Loss) per limited partner unit:
Common unit – basic	$	(2.91)	$	16.66	$	(2.91)	$	15.73
Common unit – diluted	$	(2.91)	$	15.92	$	(2.91)	$	15.27

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU	169		276		173		201

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11. SUPPLEMENTAL CASH FLOW INFORMATION


	Six Months Ended June 30,
	2021		2020
	(In thousands)
Supplemental cash flow information:
Cash interest paid	$	27,869	$	44,073



Cash paid for taxes	$	15	$	—

Noncash investing and financing activities:
Capital expenditures in trade accounts payable (period-end accruals)	$	6,059	$	12,442
Warrant issuance for GP Buy-In Transaction	$	—	$	2,300
Accretion of Subsidiary Series A Preferred Units	$	5,008	$	—

12. UNIT-BASED AND NONCASH COMPENSATION

SMLP Long-Term Incentive Plan. The Partnership’s Long-Term Incentive Plan (“SMLP LTIP”) provides for equity awards to eligible officers, employees, consultants and directors of the Partnership, thereby linking the recipients’ compensation directly to SMLP’s performance. Significant items to note:

•For the six-month period ended June 30, 2021, the Partnership granted 148,822 phantom units and associated distribution equivalent rights to employees in connection with the Partnership’s annual incentive compensation award cycle. These awards had a grant date fair value of $20.42 per common unit and vest ratably over a three-year period.

•For the six-month period ended June 30, 2021, the Partnership issued 40,002 common units to the Partnership’s six independent directors in connection with their annual compensation plan. These awards had a grant date fair value of $28.99 per common unit and vested immediately.

•As of June 30, 2021, approximately 0.3 million common units remained available for future issuance under the SMLP LTIP.

13. COMMITMENTS AND CONTINGENCIES

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

In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota (“2015 Blacktail Release”). Prior to the GP Buy-In Transaction, Summit Investments and SMP Holdings indemnified the Partnership for certain obligations and liabilities related to the incident. As a result of the GP Buy-In Transaction, the Partnership is no longer indemnified for these obligations.

A rollforward of the Partnership’s undiscounted accrued environmental remediation follows and is primarily related to the Meadowlark Rupture.


	Total
	(In thousands)
Accrued environmental remediation, December 31, 2020	$	2,929
Payments made	(512)
Additional accruals	734
Accrued environmental remediation, June 30, 2021	$	3,151

As of June 30, 2021, the Partnership has recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures expected to be incurred subsequent to June 30, 2022. Each of these amounts represent the Partnership’s best estimate for costs expected to be incurred. Neither of these amounts have been discounted to its present value.

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In the fourth quarter of 2020, the Partnership recognized a $17.0 million loss contingency for the 2015 Blacktail Release as a result of ongoing discussions with multiple federal and state government agencies, including the U.S. Department of Justice, the U.S. Environmental Protection Agency, the North Dakota Industrial Commission, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. Subsequently, on August 4, 2021, certain subsidiaries of the Partnership entered into multiple agreements with these federal and state agencies to resolve the legal matters resulting from the 2015 Blacktail Release (“Global Settlement”). The Partnership increased its loss contingency for the 2015 Blacktail Release during the three months ended June 30, 2021 by $19.3 million, resulting in an accrued loss liability for the 2015 Blacktail Release at June 30, 2021 of $36.3 million.

Key terms of the Global Settlement include (i) payment of penalties and fines totaling $36.3 million, consisting of $1.25 million in natural resource damages to the federal and state governments payable after court approval of the Global Settlement, $25.0 million payable to the federal government over five years, and $10.0 million payable to the state governments over six years, with interest applied to unpaid amounts accruing at a fixed rate of 3.25%, and of which $3.1 million is expected to be paid within the next twelve months; (ii) continuation of remediation efforts at the site of the 2015 Blacktail Release; (iii) other injunctive relief including but not limited to control room management, environmental management system audit, training, and reporting; (iv) guilty pleas for one charge of negligent discharge of a harmful quantity of oil and one charge of knowing failure to immediately report a discharge of oil; and (v) organizational probation for a minimum period of three years from sentencing, including payment in full of certain components of the fines and penalty amounts. The agreements comprising the Global Settlement are subject to a number of contingencies, including approval of the U.S. District Court for the District of North Dakota (the “U.S. District Court”) (after a public comment period of 30 days), that could prevent the Global Settlement from being finalized within its current terms.

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.

14. RESTRUCTURING

2020 Restructuring Activities. In late 2020, management initiated a plan to restructure its operations (“2020 Restructuring Plan”), resulting in certain management, facility and organizational changes. Under the 2020 Restructuring Plan, and during the three-and six-month periods ended June 30, 2021, the Partnership expensed approximately $0.1 million and $0.8 million, respectively, of costs associated with these restructuring activities. These activities consisted primarily of employee-related severance costs and are included within the General and administrative caption on the consolidated statement of operations. At June 30, 2021, the Partnership has accrued and unpaid liabilities of $0.6 million associated with the 2020 Restructuring Activities.

2019 Restructuring Activities. In late 2019, management initiated a plan to restructure its operations (“2019 Restructuring Plan”), resulting in certain management, facility and organizational changes. Under the 2019 Restructuring Plan, and during the three-and six-month periods ended June 30, 2020, the Partnership expensed approximately $0.6 million and $3.3 million, respectively, of costs associated with these restructuring activities. These activities consisted primarily of employee-related costs and consulting costs in support of the 2019 Restructuring Plan. These costs are included within the General and administrative caption on the consolidated statement of operations. At June 30, 2021, the Partnership has accrued and unpaid liabilities of less than $0.1 million associated with the 2019 Restructuring Activities.

15. SEGMENT INFORMATION

As of June 30, 2021, the Partnership’s reportable segments are:

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

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

•the Williston Basin, which is served by Polar and Divide, Meadowlark Midstream 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.

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

The Ohio Gathering reportable segment includes the Partnership’s investment in Ohio Gathering. Income or loss from equity method investees, as reflected on the statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag.

For the six months ended June 30, 2021, other than the investment activity described in Note 5 - Equity Method Investments, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the fourth quarter of 2021.

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

Assets by reportable segment follow.


	June 30, 2021		December 31, 2020
	(In thousands)
Assets (1):
Utica Shale	$	207,783	$	209,425
Ohio Gathering	252,537		259,888
Williston Basin	404,719		425,873
DJ Basin	195,089		199,920
Permian Basin	166,712		165,765
Piceance Basin	555,033		579,800
Barnett Shale	326,446		336,629
Marcellus Shale	173,918		176,441
Total reportable segment assets	2,282,237		2,353,741
Corporate and Other	191,808		146,076
Total assets	$	2,474,045	$	2,499,817

(1)At June 30, 2021, Corporate and Other included $180.9 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, 2020, Corporate and Other included $132.9 million relating to our investment in Double E.

Segment adjusted EBITDA by reportable segment follows.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)				(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	10,652	$	10,693	$	18,372	$	16,621
Ohio Gathering	6,841		7,514		13,713		15,453
Williston Basin	9,626		12,727		20,431		28,919
DJ Basin	5,106		4,339		10,453		10,250
Permian Basin	461		1,828		1,170		3,409
Piceance Basin	20,324		21,734		41,358		45,291
Barnett Shale	8,889		8,510		16,905		17,270
Marcellus Shale	5,868		4,888		11,469		10,208
Total of reportable segments' measures of profit	$	67,767	$	72,233	$	133,871	$	147,421

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)				(In thousands)
Reconciliation of income (loss) before income taxes and income from equity method investees to total of reportable segments' measures of profit:
Income (loss) before income taxes and income from equity method investees	$	(22,290)	$	53,292	$	(15,631)	$	53,730
Add:
Corporate and Other expense	40,264		9,533		48,060		21,610
Interest expense	15,502		21,990		29,455		45,818
Gain on early extinguishment of debt	—		(54,235)		—		(54,235)
Depreciation and amortization (1)	28,598		29,866		57,344		59,766
Proportional adjusted EBITDA for equity method investees	6,841		7,514		13,713		15,453
Adjustments related to MVC shortfall payments	—		2,291		—		(3,151)
Adjustments related to capital reimbursement activity	(2,225)		(237)		(3,470)		(448)
Unit-based and noncash compensation	1,048		1,846		3,015		4,569
Gain on asset sales, net	(4)		(281)		(140)		(166)
Long-lived asset impairment	33		654		1,525		4,475
Total of reportable segments' measures of profit	$	67,767	$	72,233	$	133,871	$	147,421

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

16. SUBSEQUENT EVENTS

Global Settlement. On August 4, 2021, the Partnership entered into the Global Settlement to resolve the legal matters resulting from the 2015 Blacktail Release. The Partnership increased its loss contingency for the 2015 Blacktail Release during the three months ended June 30, 2021 by $19.3 million, resulting in an accrued loss liability for the 2015 Blacktail Release at June 30, 2021 of $36.3 million. Key terms of the Global Settlement include (i) payment of penalties and fines totaling $36.3 million, consisting of $1.25 million in natural resource damages to the federal and state governments payable after court approval of the Global Settlement, $25.0 million payable to the federal government over five years, and $10.0 million payable to the state governments over six years, with interest applied to unpaid amounts accruing at a fixed rate of 3.25%, and of which $3.1 million is expected to be paid within the next twelve months; (ii) continuation of remediation efforts at the site of the 2015 Blacktail Release; (iii) other injunctive relief including but not limited to control room management, environmental management system audit, training, and reporting; (iv) guilty pleas for one charge of negligent discharge of a harmful quantity of oil and one charge of knowing failure to immediately report a discharge of oil; and (v) organizational probation for a minimum period of three years from sentencing, including payment in full of certain components of the fines and penalty amount. The agreements comprising the Global Settlement are subject to a number of contingencies, including approval of the U.S. District Court (after a public comment period of 30 days), that could prevent the Global Settlement from being finalized within its current terms. See Note 13-Commitments and Contingencies for additional information.

Exercise of the ECP Warrants. On August 5, 2021, ECP NewCo and ECP Holdings exercised all of the ECP Warrants and the Partnership issued 414,447 SMLP common units, net of the exercise price, as calculated pursuant to Section 3(c) of the ECP Warrants. The Partnership has delivered instructions to American Stock Transfer & Trust Company, LLC, its transfer agent, to issue these common units to the ECP Entities. As of June 30, 2021, the ECP Warrants were valued at $15.5 million and this amount approximated the settlement value of the SMLP common units issued in August 2021.

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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 the Partnership and its subsidiaries for the periods since December 31, 2020. 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 Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 (the “2020 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.

Overview

We are a value-driven 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, our Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and Legacy Areas are summarized below.

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

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

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our 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 in the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale customers and (iii) the sale of condensate we retain from our gathering services in the Piceance Basin segment. During the three and six months ended June 30, 2021, these additional activities accounted for approximately 16% and 19% of total revenues, respectively.

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.

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The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the "Segment Overview for the Three and Six Months Ended June 30, 2021 and 2020" section included herein.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)
Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483
Reportable segment adjusted EBITDA
Utica Shale	$	10,652	$	10,693	$	18,372	$	16,621
Ohio Gathering	6,841		7,514		13,713		15,453
Williston Basin	9,626		12,727		20,431		28,919
DJ Basin	5,106		4,339		10,453		10,250
Permian Basin	461		1,828		1,170		3,409
Piceance Basin	20,324		21,734		41,358		45,291
Barnett Shale	8,889		8,510		16,905		17,270
Marcellus Shale	5,868		4,888		11,469		10,208

Net cash provided by operating activities	$	34,787	$	35,170	$	86,217	$	105,371
Capital expenditures (1)	3,352		8,843		5,962		27,426
Investment in Double E equity method investee (2)	43,324		21,695		48,943		79,728

Borrowings under Revolving Credit Facility	—		35,000		—		90,000
Repayments on Revolving Credit Facility	(40,000)		—		(95,000)		(34,000)
Repayment of SMP Holdings Term Loan	—		(5,500)		—		(6,300)
Borrowings under Permian Transmission Credit Facility	36,000		—		53,500
Repurchase of Senior Notes	—		(76,707)		—		(76,707)
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs	—		14,764		—		47,810
Purchase of common units in GP Buy-In Transaction	—		(41,778)		—		(41,778)

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

(2)Inclusive of $0.6 million and nil of capitalized interest for the three months ended June 30, 2021 and 2020 respectively, and $1.6 million and $0.3 million for the six months ended June 30, 2021 and 2020 respectively.

Trends and Outlook

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

•Ongoing impact of the COVID-19 pandemic and its effect on demand and prices for oil;

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

•Production from U.S. shale plays;

•Capital markets availability and cost of capital; and

•Shifts in operating costs and inflation.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the 2020 Annual Report.

Ongoing impact of the COVID-19 pandemic and its effect on demand and prices for oil. We continue to closely monitor the impact of the COVID-19 pandemic on all aspects of our business, including how it has impacted and will impact our customers,

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employees, supply chain and distribution network. 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.

In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, utilizing COVID-19 pandemic tax relief (as allowed by the Consolidated Appropriations Act, 2021, the "ERC Tax Credit"), modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. 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. In addition to the significant reduction in global demand for oil and natural gas caused by the economic effects of the COVID-19 pandemic, we also experienced more oil price volatility during 2020, largely due to a macro supply and demand imbalance and actions by members of OPEC and other foreign, oil-exporting countries. This disrupted the oil and natural gas exploration and production industry and 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.

Over the past year, we have collaborated extensively with our customer base regarding production reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given continued volatility in market conditions since March 2020, and based on recently updated production forecasts and revised 2021 development plans from our customers, we currently expect our 2021 results to continue to be affected by more moderated drilling and completion activity, relative to historical periods.

Winter Storm Uri. Due to the diverse geographic footprint of our operations outside of Texas, the extreme winter weather event that occurred in February 2021 (“Winter Storm Uri”) did not have a material impact on our aggregate volume throughput during the six months ended June 30, 2021. Some of the steps taken during or prior to Winter Storm Uri to mitigate the storm’s financial impact remain subject to risks, including counterparty financial risk, potential disputed transactions and potential legislative or regulatory action in response to, or litigation arising out of, the unprecedented circumstances of the winter storm, which could affect our future earnings, cash flows and financial condition.

Debt maturities. The Partnership’s wholly owned subsidiary, Summit Holdings, has a senior secured revolving credit facility due May 13, 2022 (the “Revolving Credit Facility”). The 2022 maturity date of our Revolving Credit Facility resulted in the inclusion of this outstanding indebtedness balance into our going concern assessment for the quarterly period ended June 30, 2021. As a result, the lack of sufficient available liquidity to satisfy amounts due under our Revolving Credit Facility has raised substantial doubt about our ability to continue as a going concern.

How We Evaluate Our Operations

Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. For additional information see Note 15 - Segment Information.

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

•throughput volume;

•revenues;

•operation and maintenance expenses; and

•segment adjusted EBITDA.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three and six months ended June 30, 2021.

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 2020 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 – Summary of Significant Accounting Policies and Recently Issued Accounting Standards applicable to the Partnership.

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Results of Operations

Consolidated Overview for the Three and Six Months Ended June 30, 2021 and 2020

The following table presents certain consolidated financial and operating data.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In thousands)				(In thousands)
Revenues:
Gathering services and related fees	$	74,233	$	73,911	$	144,580	$	157,703
Natural gas, NGLs and condensate sales	16,416		10,683		37,180		24,463
Other revenues	9,392		7,413		17,599		14,744
Total revenues	100,041		92,007		199,359		196,910
Costs and expenses:
Cost of natural gas and NGLs	16,626		6,088		37,102		14,313
Operation and maintenance	17,507		21,152		34,100		42,963
General and administrative (2)	29,360		12,786		39,938		29,347
Depreciation and amortization	28,364		29,630		56,875		59,296
Transaction costs	450		1,207		217		1,218
Gain on asset sales, net	(4)		(281)		(140)		(166)
Long-lived asset impairment	33		654		1,525		4,475
Total costs and expenses	92,336		71,236		169,617		151,446
Other income (expense), net	(2,334)		276		(2,284)		(151)
Loss on ECP Warrants	(12,159)		—		(13,634)		—
Interest expense	(15,502)		(21,990)		(29,455)		(45,818)
Gain on early extinguishment of debt	—		54,235		—		54,235
Income (loss) before income taxes and equity method investment income	(22,290)		53,292		(15,631)		53,730
Income tax benefit	248		389		262		402
Income from equity method investees	2,304		3,040		4,619		6,351
Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)	1,441		1,391		1,393		1,336
Aggregate average daily throughput - liquids (Mbbl/d)	63		76		64		87

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

(2)Inclusive of a $19.3 million incremental loss contingency accrual during the three months ended June 30, 2021 related to the 2015 Blacktail Release (See Note 13 - Commitments and Contingencies for additional information).

Volumes – Gas.

Natural gas throughput volumes increased 50 MMcf/d for the three months ended June 30, 2021 compared to the three months ended June 30, 2020, primarily reflecting:

•a volume throughput increase of 80 MMcf/d for the Utica Shale segment;

•a volume throughput decrease of 41 MMcf/d for the Piceance Basin segment;

•a volume throughput decrease of 5 MMcf/d for the Barnett Shale segment;

•a volume throughput increase of 18 MMcf/d for the Marcellus Shale segment; and

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•a volume throughput decrease of 3 MMcf/d for the Permian Basin segment.

Natural gas throughput volumes increased 57 MMcf/d for the six months ended June 30, 2021 compared to the six months ended June 30, 2020, primarily reflecting:

•a volume throughput increase of 134 MMcf/d for the Utica Shale segment;

•a volume throughput decrease of 41 MMcf/d for the Piceance Basin segment;

•a volume throughput decrease of 23 MMcf/d for the Barnett Shale segment;

•a volume throughput decrease of 4 MMcf/d for the Marcellus Shale segment; and

•a volume throughput decrease of 4 MMcf/d for the Permian Basin segment.

Volumes – Liquids.

Crude oil and produced water throughput volumes at the Williston segment decreased 13 Mbbl/d and 23 Mbbl/d, respectively, for the three and six months ended June 30, 2021, compared to the three and six months ended June 30, 2020, primarily as a result of natural production declines as well as a lower number of new well connects.

For additional information on volumes, see the "Segment Overview for the Three and Six Months Ended June 30, 2021 and 2020" section herein.

Revenues. Total revenues increased $8.0 million during the three months ended June 30, 2021 compared to the prior year period, comprised of a $5.7 million increase in natural gas, NGLs and condensate sales, a $0.3 million increase in gathering services and related fees and a $2.0 million increase in Other Revenues.

Gathering Services and Related Fees. Gathering services and related fees increased $0.3 million compared to the three months ended June 30, 2020.

Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased $5.7 million compared to the three months ended June 30, 2020, reflecting:

•a $5.1 million increase in revenues in the Williston Basin;

•a $2.7 million increase in revenues in the Permian Basin; offset by

•a $2.8 million decrease in revenues in the Barnett Shale.

Total revenues increased $2.4 million during the six months ended June 30, 2021 compared to the prior year period, primarily comprised of a $12.7 million increase in natural gas, NGLs and condensate sales, a $2.9 million increase in Other Revenues, offset by a $13.1 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $13.1 million compared to the six months ended June 30, 2020, primarily reflecting:

•an $11.1 million decrease in gathering services and related fees in the Williston Basin, primarily due to lower liquids volume throughput and the expiration of a customer’s minimum volume commitment. Lower volumes are primarily associated with natural production declines as well as a lower number of new well connects during the period;

•a $3.1 million decrease in gathering services and related fees in the Piceance Basin related to lower volume throughput due to a lack of drilling and completion activity and natural production declines; and

•a partially offsetting $1.4 million increase in gathering services and related fees in the Utica Shale, primarily as a result of the completion of new wells that were commissioned in March 2021, partially offset by natural production declines on existing wells.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased $12.7 million compared to the six months ended June 30, 2020, reflecting:

•a $13.0 million increase in revenues in the Williston Basin;

•a $4.7 million increase in revenues in the Permian Basin; and

•a $1.5 million increase in revenues in the Piceance Basin; partially offset by

•a $6.7 million decrease in revenues in the Barnett Shale.

Costs and Expenses. Total costs and expenses increased $21.1 million during the three months ended June 30, 2021 compared to the three months ended June 30, 2020.

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Total costs and expenses increased $18.2 million during the six months ended June 30, 2021 compared to the six months ended June 30, 2020.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $10.5 million for the three months ended June 30, 2021 compared to the three months ended June 30, 2020, primarily driven by an increase in commodity prices.

Cost of natural gas and NGLs increased $22.8 million for the six months ended June 30, 2021 compared to the six months ended June 30, 2020, primarily driven by an increase in commodity prices.

Operation and Maintenance. Operation and maintenance expense decreased $3.6 million and $8.9 million for the three and six months ended June 30, 2021, respectively, compared to the three and six months ended June 30, 2020, primarily due to reduced employee headcount as a result of restructuring activities implemented in the fourth quarter of 2020. The Partnership realized $5.6 million of benefits during the six months ended June 30, 2021, that are not otherwise expected to occur in 2022 and future periods, as a result of commercial settlements and the ERC Tax Credit.

General and Administrative. General and administrative expense increased $16.6 million for the three months ended June 30, 2021 compared to the three months ended June 30, 2020, primarily due to a $19.3 million loss contingency accrual related to the 2015 Blacktail Release (see Note 13 - Commitments and Contingencies for additional information), partially offset by the prior period in 2020 reflecting higher restructuring and deal costs as well as a decrease in salaries and benefits associated with lower headcount from our restructuring of operations in late 2020 (the "2020 Restructuring Plan") and other cost-cutting initiatives which were realized in the three months ended June 30, 2021.

General and administrative expense increased $10.6 million for the six months ended June 30, 2021 compared to the six months ended June 30, 2020, primarily due to the aforementioned loss contingency recognized for the 2015 Blacktail Release, partially offset by the prior period in 2020 reflecting restructuring and deal costs as well as a decrease in salaries and benefits associated with lower headcount from our 2020 Restructuring Plan and other cost-cutting initiatives which were realized in the six months ended June 30, 2021.

The Partnership realized $1.0 million of ERC Tax Credit benefits during the six months ended June 30, 2021, that are not otherwise expected to occur in future periods.

Depreciation and Amortization. Depreciation and amortization expense decreased $1.3 million for the three months ended June 30, 2021 compared to the three months ended June 30, 2020.

Depreciation and amortization expense decreased $2.4 million for the six months ended June 30, 2021 compared to the six months ended June 30, 2020.

Interest Expense. The decrease in interest expense for the three and six months ended June 30, 2021, compared to the three and six months ended June 30, 2020, was primarily due to lower debt balances associated with the Partnership’s liability management initiatives completed during 2020 which included (i) open market repurchases of its Senior Notes totaling $234.2 million face value, (ii) cash tender offers of its Senior Notes totaling $72.2 million, and (iii) the consensual debt discharge and restructuring of our $155.2 SMPH Term Loan (the "TL Restructuring"). The decrease in interest expense was partially offset by a higher outstanding balance on the Revolving Credit Facility and a higher interest rate on the Revolving Credit Facility.

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Segment Overview for the Three and Six Months Ended June 30, 2021 and 2020

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 June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Average daily throughput (MMcf/d)	496	416	19%	453	319	42%

Volume throughput increased compared to the three and six month periods ended June 30, 2021, as a result of the commissioning of new wells in 2020 which resulted in a greater number of well connects during the three month period ended March 31, 2021, compared to the same period in 2020, together with the commencement of production from a new 4-well pad site during the three months ended March 31, 2021. This increase was partially offset by natural production declines from existing wells.

Financial data for our Utica Shale reportable segment follows.


	Utica Shale
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	11,349	$	11,538	(2)%	$	19,920	$	18,500	8%
Total revenues	11,349		11,538		(2)%	19,920		18,500		8%
Costs and expenses:
Operation and maintenance	658		757		(13%)	1,436		1,698		(15%)
General and administrative	28		84		(67%)	89		172		(48%)
Depreciation and amortization	1,928		1,920		—	3,854		3,847		—
Gain on asset sales, net	—		(42)		*	—		(26)		*
Total costs and expenses	2,614		2,719		(4%)	5,379		5,691		(5%)
Add:
Depreciation and amortization	1,928		1,920			3,854		3,847
Adjustments related to capital reimbursement activity	(11)		(4)			(23)		(9)
Gain on asset sales, net	—		(42)			—		(26)
Segment adjusted EBITDA	$	10,652	$	10,693	0%	$	18,372	$	16,621	11%

________

* Not considered meaningful

Three and six months ended June 30, 2021. Segment adjusted EBITDA remained consistent and increased $1.8 million, respectively, compared to the three and six months ended June 30, 2020 primarily as a result of the increased volume throughput described above, partially offset by a higher mix of lower-margin volumes on the system in the three months ended June 30, 2021.

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

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


	Ohio Gathering
	Three Months Ended June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Average daily throughput (MMcf/d)	514	540	(5)%	536	575	(7)%

Volume throughput for the Ohio Gathering system decreased compared to the three and six month periods ended June 30, 2020 as a result of natural production declines on existing wells on the system.

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


	Ohio Gathering
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	6,841	$	7,514	(9%)	$	13,713	$	15,453	(11%)
Segment adjusted EBITDA	$	6,841	$	7,514	(9%)	$	13,713	$	15,453	(11%)

Segment adjusted EBITDA for equity method investees decreased $0.7 million and $1.7 million compared to the three and six months ended June 30, 2020 primarily as a result of the lower volume throughput described above.

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Williston Basin. The Polar and Divide, Bison Midstream and Meadowlark 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 June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)	12	14	(14%)	12	14	(14%)

Aggregate average daily throughput - liquids (Mbbl/d)	63	76	(17%)	64	87	(26%)

Natural gas. Natural gas volume throughput decreased compared to the three and six months ended June 30, 2020, primarily reflecting natural production declines.

Liquids. Liquids volume throughput decreased compared to the three and six months ended June 30, 2020, primarily associated with natural production declines as well as a lower number of new well connects.

Financial data for our Williston Basin reportable segment follows.


	Williston Basin
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	12,516	$	12,407	1%	$	25,149	$	36,204	(31%)
Natural gas, NGLs and condensate sales	8,201		3,131		162%	20,428		7,455		174%
Other revenues	4,242		2,776		53%	8,749		5,918		48%
Total revenues	24,959		18,314		36%	54,326		49,577		10%
Costs and expenses:
Cost of natural gas and NGLs	8,548		941		808%	20,873		2,604		702%
Operation and maintenance	5,483		5,827		(6%)	10,407		12,549		(17%)
General and administrative	332		492		(33%)	686		1,030		(33%)
Depreciation and amortization	5,915		6,487		(9%)	11,837		12,982		(9%)
Gain on asset sales, net	—		(96)		*	(15)		(47)		*
Long-lived asset impairment	41		9		*	41		9		*
Total costs and expenses	20,319		13,660		49%	43,829		29,127		50%
Add:
Depreciation and amortization	5,915		6,487			11,837		12,982
Adjustments related to MVC shortfall payments	—		2,124			—		(3,541)
Adjustments related to capital reimbursement activity	(970)		(451)			(1,929)		(934)
Gain on asset sales, net	—		(96)			(15)		(47)
Long-lived asset impairment	41		9			41		9
Segment adjusted EBITDA	$	9,626	$	12,727	(24%)	$	20,431	$	28,919	(29%)

_______

* Not considered meaningful

Three and six months ended June 30, 2021. Segment adjusted EBITDA decreased $3.1 million and $8.5 million respectively, compared to the three and six months ended June 30, 2020 primarily due to lower liquids volume throughput on our systems as previously discussed, partially offset by lower operating expenses associated with our 2020 Restructuring Plan and other cost-cutting initiatives and lower general operating expenses.

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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 June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Average daily throughput (MMcf/d)	23	20	15%	23	26	(12%)

Volume throughput increased compared to the three months ended June 30, 2020, and increased compared to the six months ended June 30, 2020, primarily as a result of natural production declines and a decreased number of wells that were commissioned during 2021, together with temporarily shut-in production that our customers initiated in the prior-year period.

Financial data for our DJ Basin reportable segment follows.


	DJ Basin
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	5,891	$	5,228	13%	$	12,154	$	12,083	1%
Natural gas, NGLs and condensate sales	305		71		330%	415		141		194%
Other revenues	1,856		993		87%	2,560		2,027		26%
Total revenues	8,052		6,292		28%	15,129		14,251		6%
Costs and expenses:
Cost of natural gas and NGLs	214		2		*	230		11		*
Operation and maintenance	1,882		2,354		(20%)	3,794		4,870		(22%)
General and administrative	1,350		141		857%	1,669		223		648%
Depreciation and amortization	1,544		1,502		3%	3,096		3,029		2%
(Gain) loss on asset sales, net	(5)		20		*	(7)		20		*
Long-lived asset impairment	—		57		*	95		3,692		*
Total costs and expenses	4,985		4,076		—	8,877		11,845		(25%)
Add:
Depreciation and amortization	1,544		1,502			3,096		3,029
Adjustments related to capital reimbursement activity	500		544			994		1,103
(Gain) loss on asset sales, net	(5)		20			(7)		20
Long-lived asset impairment	—		57			95		3,692
Other	—		—			23		—
Segment adjusted EBITDA	$	5,106	$	4,339	18%	$	10,453	$	10,250	2%

________

* Not considered meaningful

Three and six months ended June 30, 2021. Segment adjusted EBITDA increased $0.8 million and $0.2 million respectively, compared to the three and six months ended June 30, 2020, primarily due to temporarily shut-in production that our customers initiated in the prior-year period, together with lower operating expenses associated with our 2020 Restructuring Plan and other cost-cutting initiatives and lower general operating expenses partially offset by lower volumes associated with natural declines.

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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 June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Average daily throughput (MMcf/d)	29	32	(9%)	29	33	(12%)

Volume throughput decreased compared to the three and six months ended June 30, 2020, primarily as a result of natural production declines from wells previously put in service.

Financial data for our Permian Basin reportable segment follows.


	Permian Basin
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	2,262	$	2,711	(17%)	$	4,461	$	5,022	(11%)
Natural gas, NGLs and condensate sales	6,875		4,222		63%	13,393		8,734		53%
Other revenues	121		126		(4%)	237		313		(24%)
Total revenues	9,258		7,059		31%	18,091		14,069		29%
Costs and expenses:
Cost of natural gas and NGLs	7,167		3,691		94%	14,182		7,840		81%
Operation and maintenance	1,527		1,456		5%	2,519		2,643		(5%)
General and administrative	118		84		40%	235		177		33%
Depreciation and amortization	1,464		1,387		6%	2,933		2,732		7%
Gain on asset sales, net	—		(17)		*	—		(13)		*
Long-lived asset impairment	—		—			—		182		*
Total costs and expenses	10,276		6,601		56%	19,869		13,561		47%
Add:
Depreciation and amortization	1,464		1,387			2,933		2,732
Gain on asset sales, net	—		(17)			—		(13)
Long-lived asset impairment	—		—			—		182
Other	15		—			15		—
Segment adjusted EBITDA	$	461	$	1,828	(75)%	$	1,170	$	3,409	(66)%

________

*Not considered meaningful

Three and six months ended June 30, 2021. Segment adjusted EBITDA decreased $1.4 million and $2.2 million respectively, compared to the three and six months ended June 30, 2020, primarily reflecting lower volume throughput across the system associated with natural production declines, together with an increase in the cost of natural gas and NGLs, partially offset by increased sales of natural gas, NGLs and condensate.

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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 June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Aggregate average daily throughput (MMcf/d)	326	367	(11%)	334	375	(11%)

Volume throughput decreased compared to the three and six months ended June 30, 2020, primarily as a result of natural production declines and an absence of new well connects in 2021.

Financial data for our Piceance Basin reportable segment follows.


	Piceance Basin
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	25,527	$	26,222	(3%)	$	50,311	$	53,411	(6%)
Natural gas, NGLs and condensate sales	1,025		401		156%	2,878		1,404		105%
Other revenues	1,233		1,096		13%	2,409		2,161		11%
Total revenues	27,785		27,719		0%	55,598		56,976		(2%)
Costs and expenses:
Cost of natural gas and NGLs	697		320		118%	1,816		777		134%
Operation and maintenance	5,367		5,267		2%	10,309		10,205		1%
General and administrative	345		276		25%	643		561		15%
Depreciation and amortization	10,757		11,306		(5%)	21,631		22,604		(4%)
(Gain) loss on asset sales, net	4		(83)		*	(53)		(96)		*
Long-lived asset impairment	—		—		*	970		—		*
Total costs and expenses	17,170		17,086		0%	35,316		34,051		4%
Add:
Depreciation and amortization	10,757		11,306			21,631		22,604
Adjustments related to MVC shortfall payments	—		167			—		390
Adjustments related to capital reimbursement activity	(1,403)		(289)			(1,831)		(532)
(Gain) loss on asset sales, net	4		(83)			(53)		(96)
Long-lived asset impairment	—		—			970		—
Other	351		—			359		—
Segment adjusted EBITDA	$	20,324	$	21,734	(6%)	$	41,358	$	45,291	(9%)

________

*Not considered meaningful

Three and six months ended June 30, 2021. Segment adjusted EBITDA decreased $1.4 million and $3.9 million compared to the three and six months ended June 30, 2020, primarily reflecting a decrease in volume throughput as a result of natural production declines as discussed above.

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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 June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Average daily throughput (MMcf/d)	198	203	(2%)	195	218	(11%)

Volume throughput decreased compared to the three and six months ended June 30, 2020 reflecting an absence of new well connections in 2021 together with natural production declines, partially offset by workovers and recompletions.

Financial data for our Barnett Shale reportable segment follows.


	Barnett Shale
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	10,076	$	9,877	2%	$	19,772	$	20,320	(3%)
Natural gas, NGLs and condensate sales	10		2,858		(100%)	66		6,729		(99%)
Other revenues (1)	1,012		1,778		(43%)	2,072		3,038		(32%)
Total revenues	11,098		14,513		(24%)	21,910		30,087		(27%)
Costs and expenses:
Cost of natural gas and NGLs	—		1,134		(100%)	—		3,081		(100%)
Operation and maintenance	1,852		4,564		(59%)	4,316		9,259		(53%)
General and administrative	260		513		(49%)	495		891		(44%)
Depreciation and amortization	3,798		3,788		—	7,596		7,585		—
(Gain) loss on asset sales, net	(11)		(42)		*	(11)		17		*
Long-lived asset impairment	—		—		*	289		4		*
Total costs and expenses	5,899		9,957		(41%)	12,685		20,837		(39%)
Add:
Depreciation and amortization	4,032		4,023			8,064		8,055
Adjustments related to capital reimbursement activity	(331)		(27)			(662)		(56)
(Gain) loss on asset sales, net	(11)		(42)			(11)		17
Long-lived asset impairment	—		—			289		4

Segment adjusted EBITDA	$	8,889	$	8,510	4%	$	16,905	$	17,270	(2)%

________

*Not considered meaningful

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

Three and six months ended June 30, 2021. Segment adjusted EBITDA increased $0.4 million compared to the three months ended June 30, 2020, primarily as a result of lower operating expenses associated with our 2020 Restructuring Plan together with other cost-cutting initiatives and lower general operating expenses, including lower compression operating costs, partially offset by lower volume throughput.

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


	Marcellus Shale
	Three Months Ended June 30,			Six Months Ended June 30,
	2021	2020	Percentage Change	2021	2020	Percentage Change
Average daily throughput (MMcf/d)	357	339	5%	347	351	(1)%

Volume throughput increased compared to the three and six months ended June 30, 2020 primarily due to nine new wells that were commissioned behind our gathering system in the three months ended June 30, 2021, partially offset by natural production declines.

Financial data for our Marcellus Shale reportable segment follows.


	Marcellus Shale
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Gathering services and related fees	$	6,612	$	5,928	12%	$	12,813	$	12,163	5%
Total revenues	6,612		5,928		12%	12,813		12,163		5%
Costs and expenses:
Operation and maintenance	658		933		(29%)	1,160		1,746		(34%)
General and administrative	76		97		(22%)	165		190		(13%)
Depreciation and amortization	2,301		2,300		0%	4,605		4,600		0%
(Gain) loss on asset sales, net	8		—		*	(54)		—		*
Long-lived asset impairment	(8)		—		*	130		—		*
Total costs and expenses	3,035		3,330		(9%)	6,006		6,536		(8%)
Add:
Depreciation and amortization	2,301		2,300			4,605		4,600
Adjustments related to capital reimbursement activity	(10)		(10)			(19)		(19)
(Gain) loss on asset sales, net	8		—			(54)		—
Long-lived asset impairment	(8)		—			130		—
Segment adjusted EBITDA	$	5,868	$	4,888	20%	$	11,469	$	10,208	12%

________

*Not considered meaningful

Three and six months ended June 30, 2021. Segment adjusted EBITDA increased $1.0 million and $1.3 million, respectively, compared to the three and six months ended June 30, 2020, as a result of higher volume throughput discussed above together with lower operating expenses associated with our 2020 Restructuring Plan and other cost-cutting initiatives and lower general operating expenses.

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Corporate and Other Overview for the Three and Six Months Ended June 30, 2021 and 2020

Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, construction management fees related to the Double E Project, transaction costs and interest expense.


	Corporate and Other
	Three Months Ended June 30,					Six Months Ended June 30,
	2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)					(Dollars in thousands)
Revenues:
Total revenues	$	928	$	644	44%	$	1,572	$	1,287	22%
Costs and expenses:
General and administrative (1)	26,850		11,099		142%	35,957		26,103		38%
Transaction costs	450		1,207		*	217		1,218		*
Interest expense	15,502		21,990		(30)%	29,455		45,818		(36)%
Gain on early extinguishment of debt	—		(54,235)		*	—		(54,235)		*

________

* Not considered meaningful

(1)Inclusive of a $19.3 million incremental loss contingency accrual during the three months ended June 30, 2021 related to the 2015 Blacktail Release (See Note 13 - Commitments and Contingencies for additional information).

Total Revenues. Total revenues attributable to Corporate and Other was primarily due to construction management fee revenue associated with the Double E Project.

General and Administrative. General and administrative expense increased $15.8 million and $9.9 million, respectively, compared to the three and six months ended June 30, 2020, primarily as a result of a $19.3 million loss contingency accrual related to the 2015 Blacktail Release (see Note 13 - Commitments and Contingencies for additional information), partially offset by increased restructuring and deal costs in the comparative prior year period, as well as a decrease in salaries and benefits associated with lower headcount from our 2020 Restructuring Plan and other cost-cutting initiatives.

Interest Expense. The decrease in interest expense for the three and six months ended June 30, 2021, compared to the three and six months ended June 30, 2020, was primarily due to lower outstanding debt balances associated with the Partnership’s liability management initiatives completed during 2020 which included (i) open market repurchases of its Senior Notes totaling $234.2 million face value, (ii) cash tender offers of its Senior Notes totaling $72.2 million, and (iii) the TL Restructuring that eliminated the Partnership’s $155.2 million SMPH Term Loan. The decrease in interest expense was partially offset by a higher outstanding balance and a higher interest rate on the Partnership’s Revolving Credit Facility.

Liquidity and Capital Resources

COVID-19 Impact. We are closely monitoring the continuing 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 year. Given continued volatility in market conditions since March 2020, and based on recently updated production forecasts and revised development plans from our customers, we currently expect our results to continue to be affected by decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. We expect 2021 total capital expenditures to range from $20.0 million to $35.0 million.

As we cannot predict the duration or scope of the COVID-19 pandemic and its impact on our customers and suppliers, the potential negative financial impact to our results cannot be reasonably estimated but could be material.

Indebtedness Compliance. We are currently in compliance with all covenants contained in the Revolving Credit Facility, the Permian Transmission Credit Facility and the Senior Notes. Our total leverage ratio and first lien leverage ratio (as defined in the Revolving Credit Agreement) were 5.0 to 1.0 and 3.0 to 1.0, respectively, relative to maximum threshold limits of 5.75 to 1.0 and 3.5 to 1.0, for the trailing 12-month period ended June 30, 2021. Given further deterioration of market conditions,

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decreased drilling activity, the deferral of well completions from customers, limitations on our ability to access the capital markets at a competitive cost to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and first lien leverage ratios in the future 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.

The 2022 maturity date for our Revolving Credit Facility resulted in the inclusion of this outstanding indebtedness balance into our going concern assessment for the quarterly period ended June 30, 2021. As a result, the lack of sufficient available liquidity to satisfy amounts due under our Revolving Credit Facility has raised substantial doubt about our ability to continue as a going concern. We are in the process of negotiating a new 4.5-year asset-based revolving credit facility (the “ABL Revolver”) that is expected to (i) have a borrowing capacity of $400.0 million to $500.0 million and (ii) be conditioned on the successful completion of a $700.0 million to $750.0 million offering of high yield notes (the “High Yield Notes Offering”). It is our goal to consummate both financings concurrently during the quarter ending September 30, 2021. The proceeds of the ABL Revolver and the High Yield Notes Offering would be used to repay the Revolving Credit Facility and redeem the senior unsecured notes due August 15, 2022 (the "2022 Senior Notes) issued by Summit Holdings and Finance Corp., another of our wholly-owned subsidiaries. However, there can be no assurance that we will be able to arrange an ABL Revolver or consummate the High Yield Notes Offering on terms acceptable to us prior to September 30, 2021 or at all.

If we are unable to meet our debt service and principal repayment obligations, or if we fail to comply with the leverage ratios in the documents governing our debt, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to become immediately due and payable (which would in turn trigger cross-acceleration or cross-default rights among our debt agreements). The lenders under our Revolving Credit Facility could also terminate their commitments to extend credit, the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Revolving Credit Facility or our Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors. For additional information, see the risk factor titled “We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful." included in Part II. Item 1A. Risk Factors in this report.

Credit Arrangements and Financing Activities

Revolving Credit Facility. We have a $1.1 billion senior secured Revolving Credit Facility that matures on May 13, 2022. As of June 30, 2021, the outstanding balance of the Revolving Credit Facility was $762.0 million and the unused portion totaled $314.9 million, after giving effect to the issuance thereunder of $23.1 million of outstanding but undrawn irrevocable standby letters of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility, as of June 30, 2021, was approximately $137.6 million. There were no defaults or events of default during the three months ended June 30, 2021, and, as of June 30, 2021, we were in compliance with the financial covenants in the Revolving Credit Facility.

Permian Transmission Credit Facility. On March 8, 2021, we entered into the Permian Transmission Credit Facility which allows for $175.0 million of senior secured credit facilities, including a $160.0 million term loan facility and a $15.0 million working capital facility. As of June 30, 2021, the outstanding balance of the Permian Transmission Credit Facility was $53.5 million, and the unused portion totaled $121.5 million. Our available borrowing capacity under the Permian Transmission Credit Facility as of June 30, 2021 was approximately $119.5 million. There were no defaults or events of default during the three months ended June 30, 2021, and, as of June 30, 2021, we were in compliance with the financial covenants in the Permian Transmission Credit Facility.

Exchange Offer. In April 2021, we completed an offer to exchange 18,662 Series A Preferred Units for 538,715 newly issued SMLP common units, which is net of units withheld for withholding taxes.

We may in the future use a combination of cash, secured or unsecured borrowings and issuances of our common units or other securities and the proceeds from asset sales to retire or refinance our outstanding debt or Series A Preferred Units through privately negotiated transactions, open market repurchases, redemptions, exchange offers, tender offers or otherwise, but we are under no obligation to do so.

For additional information on our long-term debt, see Note 9. Partners’ Capital and Mezzanine Capital.

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

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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, assuming that it is not refinanced. 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:


	Six Months Ended June 30,
	2021		2020
	(In thousands)
Net cash provided by operating activities	$	86,217	$	105,371
Net cash used in investing activities	(46,905)		(106,937)
Net cash provided by (used in) financing activities	(47,331)		6,263
Net change in cash, cash equivalents and restricted cash	$	(8,019)	$	4,697

Operating activities.

Cash flows provided by operating activities for the six months ended June 30, 2021 primarily reflected:

•net loss of $10.8 million plus adjustments of $90.5 million for non-cash items; and

•$6.4 million increase in working capital accounts.

Cash flows provided by operating activities for the six months ended June 30, 2020 primarily reflected:

•a $7.0 million increase in accounts receivable related to the timing of invoicing and cash collections;

•a $2.9 million increase in accounts payable due to the timing of payment obligations;

•a $3.5 million increase in deferred revenue for cash receipts not yet recognized as revenue;

•a $11.8 million decrease in accrued expenses primarily due to the timing of accrued payment obligations; and

•other changes in working capital

Investing activities.

Cash flows used in investing activities during the six months ended June 30, 2021 primarily reflected:

•$48.9 million for investments in the Double E joint venture relating to the Double E Project;

•$6.0 million cash outflow for capital expenditures;

•offset by an $8.0 million cash inflow from proceeds for the sale of compressor equipment;

Cash flows used in investing activities during the six months ended June 30, 2020 primarily reflected:

•$79.7 million for investments in the Double E joint venture relating to the Double E Project; and

•$27.4 million of capital expenditures primarily attributable to the DJ Basin of $8.4 million, the Williston Basin of $7.4 million and Summit Permian of $4.9 million.

Financing activities.

Cash flows used in financing activities during the six months ended June 30, 2021 primarily reflected:

•$95.0 million of cash outflow for repayments on the Revolving Credit Facility;

•$5.2 million of cash payments related to debt issuance costs; and

•partially offset by $53.5 million from borrowings under the Permian Transmission Credit Facility.

Cash flows used in financing activities during the six months ended June 30, 2020 primarily reflected:

•$56.0 million of net borrowings under our Revolving Credit Facility;

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

•$35.0 million of net borrowings under ECP Loans;

•$76.7 million repurchase of Senior Notes;

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

•$6.0 million of distributions to noncontrolling interest SMLP unitholders.

Contractual Obligations Update

We are leading the development, permitting and construction of the Double E Project and will operate the pipeline upon its commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $300.0 million. Assuming timely receipt of the required regulatory approvals and no material delays in construction, we expect that the Double E Project will be placed into service in the fourth quarter of 2021. On March 8, 2021, we entered into the Permian Transmission Credit Facility to finance the vast majority of our remaining capital calls associated with the Double E Project, debt services and other general corporate purposes.

On August 4, 2021, the Partnership and several of its subsidiaries entered into the Global Settlement to resolve the legal matters resulting from the 2015 Blacktail Release. As a result, the Partnership increased its loss contingency for the 2015 Blacktail Release during the quarterly reporting period ending June 30, 2021 by $19.3 million, resulting in an accrued loss liability for this matter at June 30, 2021 of $36.3 million. Key financial terms of the Global Settlement include payment of penalties and fines totaling $36.3 million over six years, with interest applied to unpaid amounts and $3.1 million owed within the next twelve months. Between 2021 and 2027, the Partnership expects to make payments of principal and interest of $3.1 million, $5.4 million, $7.2 million, $7.1 million, $7.0 million, $6.8 million, and $1.7 million, respectively, in connection with the penalties and fines included in the Global Settlement. We believe that the Global Settlement will have minimal impact on the Partnership’s strategic plans or day-to-day operations due to the ability to pay fines and penalties over multiple years and expected manageable size of installments. See Part II. Item 1. “Legal Proceedings” in this report for additional information.

Capital Requirements

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

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

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

For the six months ended June 30, 2021, cash paid for capital expenditures totaled $6.0 million which included $2.1 million of maintenance capital expenditures. For the six months ended June 30, 2021, there were no contributions to Ohio Gathering and we contributed $48.9 million to Double E (see Note 5 – Equity Method Investments). We expect 2021 total capital expenditures to range from $20.0 million to $35.0 million.

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 and Permian Transmission Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our liquidity. Our Revolving Credit Facility became current on May 13, 2021. We are in the process of negotiating the ABL Revolver that will be conditioned on the High Yield Notes Offering. It is our goal to consummate both financings concurrently during the quarter ending September 30, 2021. The proceeds of the ABL Revolver and the High Yield Notes Offering would be used to repay the Revolving Credit Facility and redeem the 2022 Senior Notes. However, there can be no assurance that we will be able to arrange an ABL Revolver or consummate the High Yield Notes Offering on terms acceptable to us prior to September 30, 2021 or at all.

Considering the current commodity price backdrop and continued uncertainty regarding impacts from the COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on accretive bolt-on opportunities of our existing systems in our Core Focus Areas.

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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 new commercial agreements with third parties and (ii) prevailing conditions and outlook in the natural gas, crude oil and NGLs and markets.

Credit and Counterparty Concentration Risks

We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

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

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

Off-Balance Sheet Arrangements

During the six months ended June 30, 2021, there were no material changes to the off-balance sheet obligations disclosed in our 2020 Annual Report other than the existence of a wholly owned marketing subsidiary’s ten-year firm transportation agreement with Double E, an equity method investment of the Partnership, that will be utilized to advantageously market natural gas for the Partnership and its customers in and around our assets in the Permian Basin. The agreement becomes effective upon the in-service date of the Double E Project and requires the Partnership to pay Double E on average $3.1 million per year, over the next ten years, for access to firm transportation on the Double E Project pipeline.

Summarized Financial Information

The supplemental summarized financial information below reflects SMLP's separate accounts, the combined accounts of the Summit Holdings and Finance Corp. (together, the “Co-Issuers”) and its guarantor subsidiaries (the “Guarantor Subsidiaries” and together with the Co-Issuers, 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, both of which 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 report.

Summarized Balance Sheet Information. Summarized balance sheet information as of June 30, 2021 and December 31, 2020 follow.

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	June 30, 2021
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	3,156	$	74,542
Noncurrent assets	5,561		2,207,593

Liabilities
Current liabilities	$	26,491	$	814,684
Noncurrent liabilities	35,537		538,339


	December 31, 2020
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	2,265	$	78,304
Noncurrent assets	6,952		2,277,807

Liabilities
Current liabilities	$	13,339	$	50,192
Noncurrent liabilities	19,987		1,398,872

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 June 30, 2021 and for the year ended December 31, 2020 follow.


	Six Months Ended June 30, 2021
	SMLP		Obligor Group
	(In thousands)
Total revenues	$	—	$	199,359
Total costs and expenses	20,669		149,152
Income (loss) before income taxes and income from equity method investees	(34,298)		21,213
Income from equity method investees	$	—	$	5,765
Net income (loss)	(34,036)		26,978


	Year Ended December 31, 2020
	SMLP		Obligor Group
	(In thousands)
Total revenues	$	—	$	383,473
Total costs and expenses	26,169		302,989
Income (loss) before income taxes and loss from equity method investees	(26,000)		122,108
Income from equity method investees	—		13,073
Net income (loss)	$	(26,016)	$	135,181

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, 2020.

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Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.

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

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

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

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

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

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

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

•actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;

•our ability to divest of certain of our assets 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;

•our ability to refinance near-term maturities on favorable terms or at all and the related impact on our ability to continue as a going concern;

•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;

•our ability to comply with the terms of the agreements comprising the Global Settlement (as defined herein), which is still subject to court approval;

•weather conditions and terrain in certain areas in which we operate;

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

•timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

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

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

•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.

Information About Us

Investors should note that we make available, free of charge on our website at www.summitmidstream.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein.

The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our indebtedness. As of June 30, 2021, we had approximately $493.5 million principal of fixed-rate Senior Notes, $762.0 million outstanding under our variable rate Revolving Credit Facility and $53.5 million outstanding under the variable rate Permian Transmission Credit Facility (see Note 7 - Debt). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, 2020. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2020 Annual Report.

Commodity Price Risk

We generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers in the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale segment customers and (iii) the sale of condensate we retain from certain gathering services in the Piceance Basin segment. Our gathering agreements with certain Barnett Shale 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. 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 price or 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 or pass through actual power expense to our customers, per the terms of each individual customer. By basing the power prices on a system and basin-relevant market, 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, 2020. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2020 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 June 30, 2021 and (ii) no change in internal control over financial reporting occurred during the quarter ended June 30, 2021, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

On August 4, 2021, certain subsidiaries of the Partnership entered into agreements to resolve government investigations into the previously disclosed discovery in January 2015 of a release of produced water into Blacktail Creek, near Marmon, North Dakota (“2015 Blacktail Release”), from a pipeline owned and operated by Meadowlark Midstream Company, LLC (“Meadowlark”), which at the time was a wholly owned subsidiary of Summit Midstream Partners, LLC (“Summit Investments,” together with Meadowlark, the “Companies”). The Companies have entered into the following agreements to resolve the U.S. federal and North Dakota state governments’ environmental claims against the Companies with respect to the 2015 Blacktail Release: (i) a Consent Decree with (a) the U.S. Department of Justice (“DOJ”), on behalf of the U.S. Environmental Protection Agency and the U.S. Department of Interior, and (b) the State of North Dakota, on behalf of the North Dakota Department of Environmental Quality and the North Dakota Game and Fish Department (“Consent Decree”), to be lodged with the U.S. District Court for the District of North Dakota (“U.S. District Court”); (ii) a Plea Agreement with the United States, by and through the U.S. Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ (“Plea Agreement”); and (iii) a Consent Agreement with the North Dakota Industrial Commission ("Consent Agreement" together with the Consent Decree and Plea Agreement, the “Global Settlement”), to be filed with the U.S. District Court.

The Consent Decree provides for, among other requirements and subject to the conditions therein, (i) payment of total civil penalties and reimbursement of assessment costs of $21.25 million, with the federal portion of penalties payable over up to five years and the state portion of penalties payable over up to six years, with interest accruing at fixed rate of 3.25%; (ii) continuation of remediation efforts at the site of the 2015 Blacktail Release; (iii) other injunctive relief including but not limited to control room management, environmental management system audit, training, and reporting; and (iv) no admission of liability to the U.S. or North Dakota. The Consent Decree is subject to the approval of the U.S. District Court after a public comment period of no less than 30 days.

Under the Plea Agreement, the Companies agreed to, among other requirements and subject to the conditions therein, (i) enter guilty pleas for one charge of negligent discharge of a harmful quantity of oil and one charge of knowing failure to immediately report a discharge of oil; (ii) sentencing that includes payment of a fine of $15.0 million plus mandatory special assessments over a period of up to five years with interest accruing at the federal statutory rate; (iii) organizational probation for a minimum period of three years from sentencing, which will include payment in full of certain components of the fines and penalty amounts; and (iv) compliance with the remedial measures in the Consent Decree. The Plea Agreement is subject to the approval of the U.S. District Court.

The Consent Agreement settles a complaint brought by the NDIC in an administrative action against the Companies for alleged violations of the North Dakota Administrative Code (“NDAC”) arising from the 2015 Blacktail Release on the following terms: (i) the Companies admit to three counts of violating the NDAC; (ii) the Companies agree to follow the terms and conditions of the Consent Decree, including payment of penalty and reimbursement amounts set forth in the Consent Decree; and (iii) specified conditions in the Consent Decree regarding operation and testing of certain existing produced water pipelines shall survive until those pipelines are properly abandoned.

The agreements comprising the Global Settlement are subject to a number of contingencies, including approval of the U.S. District Court, that could prevent the Global Settlement from being finalized within its current terms.

The foregoing description of the Global Settlement and the matters contemplated thereby in this Quarterly Report on Form 10-Q is only a summary and is qualified in its entirety by reference to the governing documents, copies of which are filed as Exhibits 10.1, 10.2 and 10.3 and are incorporated by reference herein.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of the 2020 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 factors presented below are an update to, and should be considered in addition to, the risk factors previously disclosed by us in our 2020 Annual Report.

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We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful. Because the maturity date of our Revolving Credit Facility is within twelve months of the date that these financial statements were issued, there is substantial doubt about our ability to continue as a going concern.

Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our Revolving Credit Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our operating cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to adopt alternative financing strategies, such as reducing or delaying investments and capital expenditures, selling assets, seeking additional capital or restructuring or refinancing our indebtedness, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.

The 2022 maturity date of our Revolving Credit Facility resulted in the reclassification of this long-term indebtedness as current and therefore the inclusion of this outstanding indebtedness balance into our going concern assessment for the quarterly period ended June 30, 2021. As a result, the lack of sufficient available liquidity to satisfy amounts due under our Revolving Credit Facility has raised substantial doubt about our ability to continue as a going concern.

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior secured or unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates, may require the pledging of collateral and may require us to comply with more onerous covenants than we are currently subject to, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our Revolving Credit Facility and the indentures governing our Senior Notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.

Further, if for any reason we are unable to meet our debt service and principal repayment obligations, or if we fail to comply with the leverage ratios in the documents governing our debt, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights among our debt agreements), the lenders under our Revolving Credit Facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Revolving Credit Facility or our Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships.

Any modification to the U.S. federal income tax laws and interpretations could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. One recent proposal was contained in the Biden Administration’s budget proposal released on May 28, 2021, which would repeal the application of the qualifying income exception to partnerships with income and gains from activities relating to fossil fuels for taxable years beginning after 2026. We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

Item 5. Other Information.

Exercise of the ECP Warrants. As previously disclosed, in May 2020, we, at the closing of the transaction by which it acquired its General Partner, issued (i) a warrant (the “ECP NewCo Warrant”) to purchase up to 537,307 SMLP common units to SMP

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TopCo, LLC, a Delaware limited liability company (“ECP NewCo”) and affiliate of Energy Capital Partners II, LLC (“ECP”), and (ii) a warrant (together with the ECP NewCo Warrant, the “ECP Warrants”) to purchase up to 129,360 SMLP common units to SMLP Holdings, LLC, a Delaware limited liability company and affiliate of ECP (together with ECP NewCo, the “ECP Entities”).

On August 5, 2021, the ECP Entities cashlessly exercised all of the ECP Warrants for an aggregate of 414,447 SMLP common units, net of the exercise price, as calculated pursuant to Section 3(c) of the ECP Warrants. We have delivered instructions to American Stock Transfer & Trust Company, LLC, its transfer agent, to issue these common units to the ECP Entities.

Resignation of Director. On August 4, 2021, Robert M. Wohleber, a member and Lead Independent Director of the Board of Directors of our General Partner (the “Board”), announced to the Board his intention to resign from the Board effective December 31, 2021. There were no disagreements between Mr. Wohleber and the General Partner, the Partnership or any officer or director of the General Partner that led to Mr. Wohleber’s decision to resign. Mr. Wohleber has served on the Board since 2013 and as the Lead Independent Director since 2020. A replacement for Mr. Wohleber will be named at a later date.

Item 6. Exhibits.


Exhibit number		Description
3.1		Fourth Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.1 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
3.2		Second Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed June 2, 2020 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1	+	Joint Factual Statement
10.2	+	Criminal Plea Agreement
10.3	+	Consent Decree
22.1		Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities (Incorporated herein by reference to Exhibit 22.1 to SMLP's Report on Form 10-Q filed May 8, 2020 (Commission File No. 001-35666)
31.1	+	Rule 13a-14(a)/15d-14(a) Certification, executed by Heath Deneke, President, Chief Executive Officer and Director
31.2	+	Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, Executive Vice President and Chief Financial Officer
32.1	+	Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer
101.INS	*	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	*	Inline XBRL Taxonomy Extension Schema
101.CAL	*	Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF	*	Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB	*	Inline XBRL Taxonomy Extension Label Linkbase
101.PRE	*	Inline XBRL Taxonomy Extension Presentation Linkbase
104	*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

+ Filed herewith.

* Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to

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liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.

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SIGNATURES

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


			Summit Midstream Partners, LP
			(Registrant)

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

August 6, 2021			/s/ MARC D. STRATTON
			Marc D. Stratton, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Document


Case 1:21-cr-00152-DMT Document 2 Filed 08/05/21 Page 1 of 17

UNITED STATES DISTRICT COURT DISTRICT OF NORTH DAKOTA

UNITED STATES OF AMERICA,

SUMMIT MIDSTREAM PARTNERS, LLC

Defendant.

Case No.

JOINT FACTUAL STATEMENT

The United States of America and the Defendant, Summit Midstream Partners, LLC hereby agree that this Joint Factual Statement is a true and accurate statement of the Defendant’s criminal conduct, that it provides a sufficient basis for the Defendant’s plea of guilty to the charges contained in the Criminal Information in the above-captioned matter and as set forth in the Plea Agreement signed this same day, and that had this matter proceeded to trial, the United States would have proven the facts set forth in this Joint Factual Statement beyond a reasonable doubt.

Executive Summary

On January 7, 2015, Summit Midstream Partners, LLC and Meadowlark Midstream, LLC (the two closely related corporations are collectively referred to herein as “Summit”) reported to federal and state authorities that there had been an unpermitted discharge of oil-contaminated “produced water” from a midstream pipeline that Summit owned and operated. This report, as well as subsequent reports made by Summit, failed to disclose relevant information known about the discharge. In actuality, the spill, which contained oil as well as other pollutants and high levels of salt, started on August 17, 2014, and continued unabated for five months before Summit confirmed it on January 6, 2015. During that time, in excess of 29 million gallons of produced water were spilled into the environment, contaminating the land and more than 30 miles of North Dakota waterways. Summit’s failure to discover the pipe rupture and to stop the ongoing discharge was the result of its own negligence.

The pipeline ruptured approximately 178 feet west of Blacktail Creek, a jurisdictional water of the United States subject to various laws including the Federal Water Pollution Control Act (Clean Water Act), the Oil Pollution Act of 1990, and North Dakota state law. Summit failed to immediately report the spill as required by law and provided incomplete and misleading information including in subsequent calls on January 18, and 21, 2015, as well as a certified submission to the U.S. Environmental Protection Agency on September 3, 2015.

The discharge is visible in photographs taken by satellites orbiting the earth. A photograph taken from space on August 28, 2014, shows a crescent-shaped dark patch on the soil at the spill


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location curving toward Blacktail Creek. Aerial photographs taken in September, October, and November 2014 also show the same crescent-shaped dark patch at the spill location and discoloration of Blacktail Creek downstream of the spill location with no discoloration upstream. An aerial photograph taken on December 10, 2014, shows the crescent-shaped dark patch, and while Blacktail Creek appears to be covered with ice and/or snow upstream of the spill location, ice and/or snow is not present downstream of the leak location.

As set forth in greater detail below, Defendant admits that it violated the Clean Water Act, as amended by the Oil Pollution Act, in the two ways charged in the Criminal Information.

Count 1: In pleading guilty to Count 1, Defendant Summit admits that between on or about August 16, 2014, through and including on or about January 6, 2015, it caused the discharge of approximately 700,000 barrels of produced water, including harmful quantities of oil, into U.S. waters, that Summit acted negligently, and that Summit’s negligence was a proximate cause of the discharge in violation of 33 U.S.C. §§ 1319(c)(1)(A) and 1321(b)(3). Summit’s negligence included the design, construction and operation of the Marmon Water Gathering System pipeline, as well as the negligent failure to find and stop the spill after learning of objective signs of a leak. As set forth below, Summit started operations without line balancing or otherwise having a reliable leak detection system in place. Even after it learned of major drops in pressure and volume – objective signs of a leak – Summit negligently continued operations and thus caused millions of additional gallons to be discharged into U.S. waters without learning the cause or pausing operations.

Count 2: In pleading guilty to Count 2, Summit admits that from on or about January 6, 2015, through and including, on or about January 21, 2015, it failed to immediately report the discharge of a harmful quantity of oil into U.S. waters to the United States, that it knew oil had been discharged, and that it acted knowingly, in violation of 33 U.S.C. § 1321(b)(5). As detailed herein, the failure to report the discharge included a knowing failure to provide all relevant information regarding volume, duration, and other aspects of the spill. Summit’s reports to federal and state authorities were incomplete and misleading. Summit officials had information about the duration and volume of the spill that were relevant to an emergency response but were not shared. Furthermore, the statements that were made to state and federal authorities were incomplete, misleading, and not responsive to specific requests for information.

Background

Defendant Summit Midstream Partners, LLC was part of a group of interrelated corporate entities that through various subsidiaries owned and operated a midstream pipeline designed to transport produced water from drilling wells to disposal wells. In this instance, both the drilling wells and the disposal wells were owned and operated by the same unrelated company, referred to herein as Company A. Under the terms of a contract, Summit was paid a per barrel fee to transport the produced water from the well pads to the disposal wells. Summit owned and operated the pipeline, not the drilling wells or the disposal wells at either end.


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Produced water is a collection of pollutants that are the byproduct of the hydraulic fracturing method of oil exploration and extraction commonly known as “fracking.” Fracking involves injecting water, sand and chemicals at high pressure into holes drilled in subterranean rock which causes gas and oil trapped inside the rock to be released. The term fracking refers to how the rock is fractured apart by the high-pressure mixture. The produced water caused by this method of drilling in the Bakken region of North Dakota had a large concentration of saline, as well as oil, radioactive substances and other pollutants, including ammonia, aluminum, arsenic, boron, copper, nickel, selenium, zinc, barium, benzene, and thallium.

Summit’s pipeline, known as the Marmon Water Gathering System (“Marmon System”), was located in Williams County, North Dakota, and consisted of approximately 96 miles of underground, interconnected pipeline. It ran from approximately 37 oil and gas drilling well pads (“well pads”) to the disposal facility, where the produced water was held in storage tanks and ultimately injected into two underground disposal wells. At both ends of the pipeline, oil was separated from the produced water. Alongside the produced water pipeline, was an underground oil pipeline that transported the oil.

The produced water that accumulated from Company A’s oil exploration was transferred into holding tanks located on the well pads, and then transferred to Summit’s pipeline via Lease Automatic Custody Transfer (LACT) units for transport to the disposal well sites (or alternatively taken to the disposal wells by tanker truck). The LACT units and the pipeline were owned and operated by Summit Midstream Partners, LLC (Summit) and Meadowlark Midstream Partners, LLC (Meadowlark), two related entities sharing common owners, corporate officers, offices, managers, and employees.

Negligence During Pipeline Installation and Testing

Construction of the Marmon System began in or about October 2013. The pipeline material used in the Marmon System was a thermoplastic pipe, reinforced with high-strength glass fibers embedded in an epoxy matrix, surrounded by an outer thermoplastic layer. The pipeline manufacturer’s “Installation Guide,” which Summit provided to Company B, a contractor it hired to install the pipeline, recommended that a representative of the manufacturer be present during the installation and testing of the pipeline. However, several portions of the pipeline were installed without a manufacturer’s representative on site, including the portion of the pipeline where the spill occurred.

The Installation Guide described the proper way to handle, install, and test the pipe, including but not limited to: (1) that care should be taken during backfilling the pipe, particularly that first foot of cover “should not contain any large rocks, and the pipe should be covered gently, taking care not to allow mechanical equipment to come into contact with the pipe”; (2) that the pipe “will tend to tighten around any bends or restraints and can be damaged, so provision must be made for this”; and (3) that if “soil is frozen, extra care must be taken not to allow frozen lumps to come into contact with the pipe.” The Instruction Guide was not closely followed and all of the aforementioned problems were documented in daily reports to Summit by its contractors.


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The Installation Guide also recommended that the pipe be tested with water, not gas or air, at 1.2 to 1.5 times the rated pressure of the pipe after construction and before operation. This called for Summit’s pipeline, which is rated to 750 pounds per square inch (psi), to be tested at 900 to 1,125 psi. Summit did not follow this guidance and instead pressure-tested the pipeline with nitrogen gas at approximately 700-750 psi. Even so, that testing resulted in numerous blowouts and leaks of the nitrogen gas.

Summit employees and contractors were aware of the blowouts that occurred during pressure testing. Summit’s North Dakota Construction Manager (“Construction Manager”) at the time emailed a representative of Company B on July 6, 2014:

We need to discuss what is happening here with the tests. There has been entirely [too] many leaks in different areas on this line to be able to put this problem off on the material being used. From ends blowing off, pipe blowing out, rocks on line, etc. This is a salt water line that we have to feel comfortable with before putting into service.

How many leaks have we had on this section to date, With all of the [pipe] that we have put in so far I have a hard time believing that the [manufacturer of the] pipe is the issue. The [pipe] is pretested to 1.5 times rated pressure before ever being delivered. While there is a chance of some hitting or dinging this pipe in transit,

installation is by far the big issue with failures in this product.

Company B’s representative responded:

… I agree it probably is some installation problems. I've been involved the last month on trying to figure out what's going. The ones that concern me is it holds for one to two days at 500 lbs of air and I know of a couple of test that has held at 750 lbs for 4 to 7hrs 45 minutes and blew. I'll get the information together and bring it when we meet tomorrow.

A few days later, Summit’s installation inspector raised questions about the number of blowouts and testing at the lower-than recommended testing pressures, questioning Summit’s Construction Manager whether the pipe manufacturer would “stand behind the pipe if we have a major blow-out” but had not followed the recommended pressure testing. There is no evidence that testing pressure increased following this email.

It cannot be known with certainty what caused the pipe rupture on August 17, 2014, or whether proper testing before startup would have revealed a weakness, or, whether a weakness in the pipe was the result of negligent installation. What is known, is that the installation was negligent and that the rupture was consistent with negligent installation. The negligent installation had the potential to be a cause or contributing cause to the blow out.


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Negligent Design and Operation: No Line Balancing

Pipeline systems conveying hazardous substances have historically used both inlet meters and outlet meters so that the data from each can be assessed to determine whether the volume of substances entering the system at the designated entry points is equal to the volume of substances exiting the system at designated delivery points. This practice is called “line balancing,” and is an important method of leak detection.

The original proposal to build the Marmon System for the conveyance of produced water, as presented to Summit’s Board of Directors for approval in June 2013, included line balancing, with both inlet meters at the drilling well sites and outlet meters at the exit to the disposal wells. But Summit started operating the pipeline with no outlet meters. Summit had only inlet meters at the LACT units, measuring the amount of produced water entering the pipeline and were the data used to charge Company A for transporting the produced water to the disposal wells. Consequently, because Summit did not install outlet meters, it lacked the ability to conduct line- balancing calculations that would have notified Company A of a leak.

Summit managers, officers, and directors at the time were aware that the Marmon System lacked outlet meters and understood that without them line balancing could not be used to alert them of a leak. For example, on June 10, 2014, Summit’s Construction Manager wrote to Summit employees, including Summit’s Director of Project Management and Area Operations Manager, acknowledging the absence of outlet meters and noting “we will have to install the water meters on our piping before it gets to” the saltwater disposal (“SWD”) facility. On July 11, 2014, a pipeline manager sent an email to senior corporate executives stating in part that “we really don’t have a good leak detection system.” On that same day, a Summit Vice President at the time wrote an email to other managers indicating that the contract with Company A did not specify which entity was responsible for providing outlet meters, but that he believed “we should have these to balance our system. Maybe the SWD well operator would share this cost with us, but it would be hard to get [Company A] to pony up for this.” A few days later, a Summit operator sent an email to Summit’s Director of Measurement stating: “[W]e don’t account for all of the water yet but that is coming. We do not want to have a leak and not know. We are adding Meters at the [Company A] disposal wells in the near future.”

In early July 2014, there was a produced water spill from a pipeline operated by a different company in North Dakota that took a week to discover because that pipeline lacked meters necessary for line balancing. On July 15, 2014, the then President and CEO of Summit wrote an internal email to other high level managers incorrectly stating: “[m]y understanding . . . is we have alarms in place that would have caught pressure drop and volume drop much sooner.” Summit’s Vice President of Engineering at the time responded to the President and copied other managers on July 28, 2014, alerting them to the absence of outlet meters on the Marmon System and stating “we will have to procure and install these.” At the time, Summit’s pipeline was already in operation and no additional measures were taken to manage the risk until outlet meters could be installed.


Case 1:21-cr-00152-DMT Document 2 Filed 08/05/21 Page 6 of 17

Summit subsequently purchased outlet meters in August 2014, installed them in September, but did not connect power to make them operational until December 24, 2014, and did not read or analyze the data collected by the meters until January 1, 2015. As set forth below, on various dates during this period, Summit employees received notices from Company A about large volumes of produced water that were missing, causing at least one Summit employee to speculate about a leak and whether to shut down the pipeline.

Summit engineers and managers readily conceded to government investigators that it was imprudent to start up the pipeline without line balancing. In pleading guilty to Count 1, Summit admits that regardless of the cause of the pipe rupture, it was negligent because it operated the Marmon System produced water pipeline without an effective leak detection system in place, and continued to operate it without line balancing, and without effective aerial and ground patrols. Defendant further admits that this negligence was a proximate cause of the ongoing and continuous discharge of oil-contaminated waste into Blacktail Creek and U.S. waters.

Negligent Operation: Signs of and Search for a Possible Leak

A.Loss of Pressure

While Summit’s produced water pipeline lacked outlet meters to account for any loss of volume, it had pressure meters at each of the drilling well pads. The pressure meter at the State/Moline well pad – the well pad closest to the spill location – went into operation on or about July 17, 2014. Over the next month, the pipeline pressure was above 500 psi. On August 17, 2014, there was a sudden and dramatic drop in pressure to less than 100 psi. Thereafter, the pressure largely stayed below 200 psi. The sudden and sustained loss of pressure did not go entirely unnoticed, but it was not addressed, and this negligence was a proximate cause of continued discharges of oil-contaminated produced water into U.S. waters.

On October 14, 2014, Summit’s Construction Manager sent an email to other Summit employees about “extreme low pressure” on the Marmon System. He further noted: “I am not too sure we may not have a problem.” And he continued: “The ops guys have driven the pipelines looking to see if there are leaks and I currently have people driving the lines as well looking for problems.” In a follow-up email on that same day, Summit’s Construction Manager wrote to Summit’s Facilities Engineer: “Well I hope I am wrong” and added the low pressure on the pipeline “does not seem possible” prompting his colleague to respond: “Not good. We may want to consider shutting down.” Summit did not shutdown the pipeline.

The pressure data (in psi) by date is reflected in the diagram below. This data was always available to Summit. It was accessed within a few days of the spill being discovered, but was not shared with federal or state authorities.


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https://cdn.kscope.io/e23a2df3d4766ac41f156badbb5cd611-image_0.jpg

B.Volume Discrepancies

Summit had no ability to conduct line balancing on its own. But Company A – which paid Summit to transport the produced water from its drilling wells to its disposal wells – had injection meters at the injection wells where the produced water from the Marmon System was ultimately disposed into the ground. Company A could not perform true line balancing because some of the produced water was stored in holding tanks and some was transported by truck, but it could perform a rough calculation with the data it possessed. In the first such notification on November 4, 2014, Company A informed Summit that 115,000 barrels (4,830,000 gallons) of produced water were missing for the month of October, which is approximately 3,700 barrels (155,400 gallons) per day.

On December 3, 2014, Company A sent an email to two Summit managers asking: “Can you guys help us understand the differences between the volumes from the ledger sheet [inlet meter volumes] and the injection volumes that we are measuring at the SWDs? We’ve completed pump down tests to test the meters at each of the SWD’s is why we are inquiring.” The pump down test was used to determine the accuracy of injection well meters so that they could be recalibrated if necessary.

Approximately one week later, on December 10, 2014, not having received a response, Company A emailed the same group, adding Summit’s Construction Manager to the chain, noting a discrepancy of approximately 4,900 barrels (205,800 gallons) per day. The Company A Facility Engineer also opined: “[I]f we are confident in the Injection Volume numbers, and also confident on the LACT Pipeline volumes. Then the discrepancy has to be attributed to the pipeline. We either have a leak or water is being diverted/transported to an alternative route. With a discrepancy of close to 5,000 [barrels per day] and no leaks have been identified, I lean toward the later.” On December 16, 2014, having received no response again, Company A again emailed the group: “Gents, Any new word on this matter?” At a rate of 4,900 barrels (205,800 gallons) per day, approximately 102,900 barrels (4,321,800) were discharged between December 3, 2014 (when Company A verified the accuracy of its meters by doing the pump down test) and December 24, 2015 (when Summit connected power to its meters).


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On December 24, 2014, Summit put the Marmon System outlet meters into service. With operational inlet meters and outlet meters, for the first time, Summit was able to perform line balancing on the Marmon System. But it did not do so immediately. The first time Summit examined data from the newly installed outlet meters was January 1, 2015, when a Summit employee sent photographs of the outlet meters to Summit’s Field Operator, Construction Manager, and Area Operations Manager, noting that the outlet meters were operational, and would be read visually on a daily basis until they could be connected to a monitoring system that could do so remotely. Although a comparison of the readings from the newly installed outlet meters to the readings from Summit’s inlet meters shows a continuing loss of produced water, there is no evidence that Summit actually compared the readings at this time. There is similarly no evidence that senior management considered shutting down the pipeline.

On January 6, 2015, Company A sent an email to a Summit Vice President of Engineering at the time, providing him with the readings from Summit’s inlet and outlet meters for the period December 25, 2014, to January 3, 2015. The readings showed that after Summit’s outlet meters were operational, Summit’s records showed 67,007 barrels entering the pipeline and 9,177 barrels existing, a difference of 57,830 barrels (2,428,860 gallons) missing from the pipeline over that 10- day period. The pipeline was not shut down immediately upon receipt of Summit receiving this data from Summit’s meters.

C.Efforts to Find a Leak

To the extent that Summit had a leak detection method, it was to have employees and contractors drive the right-of-way visually looking for anomalies and to hire a company to conduct routine aerial patrols. The record shows that various employees conducted routine line patrols in August, October, November and December of 2014. Documents show that contractors were asked to specifically look for a leak, but there is no record that the employees and contractors who were asked to search for a leak were provided with any guidance of what to look for or how to conduct the search. There is also no evidence that any of the personnel involved left their vehicles to search.

Summit’s aerial patrols were conducted by a contractor. Only routine patrols were conducted and the aerial contractor was not advised that Summit suspected a leak. There is no evidence that Summit was involved in supervising or managing an aerial search for a possible leak. The aerial contractor did not search using imaging such as photography or forward looking infrared radar. Based upon the satellite images of the spill, and visual observations after its discovery, the spill would have been visible from an aircraft on the dates when patrols were conducted in August, September October, November and December, 2014.

Summary of Negligence

At various points in time, Summit had opportunities to discover and stop the leak. Employees were asked about these missed opportunities. A common refrain was that there was too much “noise.” They explained that Summit’s focus was on rapid expansion, and that there were many different priorities such that environmental compliance was not made a top priority.


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Summit at the time also lacked a clear assignment of responsibility for managing environmental safety and compliance. In pleading guilty to Count 1, Summit acknowledges that it was negligent to continue

to operate the Marmon System pipeline: (1) without determining the cause of the significant loss of pressure in the pipeline that began on August 17, 2014; (2) without determining the cause of the volume discrepancies being reported by Company A starting on November 4, 2014, and continuing each month; (3) without making operational the outlet meters purchased in August 2014 and installed in September 2014; and (4) without reading the outlet meters that began collecting data on December 24, 2014. Each of these acts of negligence was a proximate cause of the continuing discharge.

Failure to Report

The Clean Water Act, as amended by the Oil Pollution Act of 1990, required Summit to immediately notify the National Response Center (“NRC”) of any discharge of a harmful quantity of oil into the navigable waters of the United States. This is a core federal requirement and integrally linked to the federal government’s review of more than 25,000 such notifications each year. The information is relayed to federal first responders depending on various factors including severity of the leak. North Dakota law also mandated immediate reporting and further required that Summit share all relevant information.

Although key employees at Summit suspected a leak for some time, as set forth herein, Summit did not find physical evidence to confirm it, nor shut down the pipeline until the afternoon of January 6, 2015. Summit did not notify the federal government’s NRC until the following afternoon.

The leak was confirmed on the afternoon of January 6, 2015, when a contractor employed by Company A noticed that Blacktail Creek was unexpectedly flowing where it crossed under Highway 85 while the rest of the landscape was frozen. The high salinity of produced water lowers its freezing point, and the more salt, the lower the freezing point. He called Summit’s Pipeline Operator #1, who, upon arrival, tasted the water in the creek and found it to be very salty consistent with a produced water discharge. The two searched in the dark for the source but could not find it. At 5:39 p.m. (MT) on January 6, 2015, a Summit Vice President wrote to Summit’s Construction Manager, informing him: “We think there is a leak by State Moline. [Operator #1 is] there now. He tested water in the creek and its brine.” At 6:05 pm, Summit’s Construction Manager replied in part: “Just don’t know how all missed it. Especially [where] they found it.” Summit executives and managers were notified by telephone, in-person conversations, and email on January 6, 2015, that it was confirmed that Summit’s pipeline had a leak and that the pipeline had been shut down.

At approximately 7:00 a.m. (MT) the following morning, Operator #1 found the exact spill site located approximately three quarters of a mile from the highway crossing where he tasted salt in the creek the night before. He observed a cone-shaped hole in the ground, 5-6 feet deep, filled with water. No water was flowing out of the hole because the pipeline had been shut down the night before, but he saw marks in the soil, indicating that water had flowed from the hole, around a small hill, and down over the ground into Blacktail Creek. The ruptured pipe was


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located approximately 178 feet from Blacktail Creek. Visible oil was seen and photographed that day on the surface of Blacktail Creek. Operator #1 also observed oil staining on the snow and ice near Blacktail Creek.

That same morning, numerous Summit managers and employees participated in a conference call. Notes of the conversation were taken by Summit’s former Environmental Director including:

–[P]otential for leak to have started upon startup

–[L]and area at the leak site may be 4-5 acres contaminated

–~ 11/27/14 – [Summit’s Area Operations Manager and Construction Manager] heard about volumes from [Company A]

–12/24/14 – our water meter was installed to allow us to meter out inlet/outlet to confirm the liquid loss that we have suspected but not been able to identify

–12/31/14 – meter is tied into SCADA and we can see the volume discrepancy but can’t verify data

–[P]ossible loss is 5,000 – 6,000 bbls/d on leak day?

–1/6/15 – got a call from [Company A] saying there were discrepancies between shipping and receiving.

–1/6/15 … [Summit’s Pipeline Operator] went out at night to see the area and thought he saw some ground staining and possible unfrozen brine water.

–[T]here is brine/oily water on top of the ice near the site, going to put out booms, and diapers

Before noon on January 7, 2015, Summit engaged at least two contractors to begin to clean up the spill.

Summit called North Dakota authorities at 4:03 p.m. (MT) on January 7, 2015. It reported “an unknown quantity of saltwater brine was released from the pipeline leak. Some of the released saltwater entered the Blacktail creek[.]” State authorities asked if Summit had reported the discharge to the federal NRC as required but it had not done so.

At 4:38 p.m. (MT) on January 7, 2015, Summit called the NRC and reported “an unknown quantity of saltwater” into Blacktail Creek. When asked by the NRC operator what time the incident took place, the Summit caller responded: “I don’t know the exact time.” The NRC operator said they could use the time it was being reported and Summit’s representative said “Sure, let’s, let’s do 7:00 a.m. today. So January 7th at 7:00 a.m.” Summit reported that “The product is saltwater.” (“Saltwater” is another term used in the oil and gas industry for produced water.) When asked by the NRC hotline operator to describe if there was any sheen on


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the water, the Summit representative replied: “Uh, I can’t, I don’t think there’s any sheen on the water…. It’s a brine.” The notes from the meeting earlier that morning, that the caller had attended, state that Summit had “suspected but been unable to identify” a leak since at least December 24, 2014. Those notes

also stated: “[T]here is brine/oily water on top of the ice near the site, going to put out booms, and diapers.” A sheen on the water or oil on the shoreline are legal definitions of a harmful quantity of oil. Summit also stated that it did not “know the quantity” spilled.

In Summit’s calls to North Dakota and federal authorities on January 7, 2015, it did not indicate that it had located the spill the day before, or that it had been looking for a possible spill for months. Summit also did not mention that it had received data the previous day that more than

2.4 million barrels were unaccounted for since December 25, 2014, based on Summit’s own meters, that it had received other reports of large volumes of missing fluid dating back to October, or that there had been a sustained pressure drop on this line since August 17, 2014.

On January 13, 2015, Summit’s former executives and employees updated North Dakota officials and, for the first time, reported a volume. According to Summit, 70,878 barrels were lost from the pipeline from December 25, 2015, to January 6, 2015. This period of time corresponds to the day after Summit’s outlet meters were installed to the day the pipeline was shut down. Summit did not inform North Dakota that there was data showing the duration of the spill was longer than that period of time, nor did Summit share that it had data from Company A showing a larger volume may have been discharged.

On January 18, 2015, Summit updated its report to the NRC. In the call to NRC on January 18, 2015, Summit changed the substance spilled from “saltwater” to “produced water with entrained hydrocarbons.” In response to questions from the NRC operator, Summit again stated that the spill occurred on January 7th at 7:00 in the morning and that the spill quantity was still unknown. That same day, Summit was sufficiently concerned about the oil content being found in the area of the rupture that it tested the oil pipeline that ran parallel to the produced water pipeline to make sure it was not also leaking.

On January 21, 2015, Summit for the first time reported an estimated volume to the NRC. This report was prompted by an EPA official who requested that Summit provide information regarding the volume released. What to report and how to report it was a subject of discussion between and amongst Summit executives, managers and counsel. Summit’s former Environmental Director at the time made the call to the NRC as he was directed and stated: “I want to update the spill quantity.” “Can I put potentially 70,000 barrels, cause it’s not a definitive number, it’s just what we’re updating the report with.” In making this report, Summit did not qualify the information or state the estimate of 70,000 barrels was based only on 14 days of data, nor did it provide other relevant information at its disposal indicating that the spill had lasted longer than 14 days and involved a larger quantity. Summit’s updated written report stated “Potentially 70,000 barrels of produced water and an unknown quantity of hydrocarbons associated with the produced water.”

Summit also issued a press release on January 21, 2015, which stated:


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Based on a preliminary review of the [Summit’s] metering data, the estimated volume of the produced water released from the ruptured pipeline is approximately 70,000 barrels. Since commencing remediation efforts on January 6, 2015, approximately 65,000 barrels of water have been extracted from Blacktail Creek. It

is likely that a significant amount of this water was freshwater from the creek and not all produced water. Sampling data indicates that in general, as expected, chloride concentrations have decreased since the release. The produced water also contained entrained hydrocarbons.

Summit provided the U.S. EPA with a written response to a Request for Information regarding the spill. The response was certified on September 3, 2015, by Summit’s then Executive Vice President who also served as Chief Compliance Officer and General Counsel. Among other things, Question 21 of the Request for Information asked Summit to describe the quantity of each substance discharged, how those quantities were determined, and all documents relating to Summit’s determination. Summit answered, in part:

Meadowlark preliminarily estimated that approximately 70,000 barrels of produced water might have leaked from the Marmon Pipeline. Meadowlark based the estimate on a comparison of meter data gathered at each LACT unit and data from a meter installed at the inlet to the UIC facility for the period when both sets of meters were operational. Meadowlark relies on this meter data because these were the only two meters owned and operated by Meadowlark. Meadowlark may or may not revise this value upwards or downwards depending on many possible factors, such as meter reliability, human error, evaluation of operations and environmental data and third-party information.

At no time prior to this Plea Agreement did Summit update this statement.

Summit had reason to know that its reports to state and federal government were incomplete and misleading. On January 9, 2015, Summit’s then Vice President of Engineering conducted an analysis of the available data, including the recorded history of pipeline pressure, Company A’s meter readings, and Summit’s more limited data. Based on his review of the data, he found substantial evidence that the spill began between 11:00 p.m. and 12:00 a.m. on August 16-17, 2014, and that more than 700,000 barrels (29.4 million gallons) of fluid had been lost from the pipeline. A day later, this Vice President sent an email with a spreadsheet containing the data and his calculations to Summit executives including the President and Chief Executive Officer, the Executive Vice President who also served as Chief Compliance Officer and General Counsel, and others.

This email and the spreadsheet were withheld from the grand jury and from civil investigators under a claim of privilege. It also was not provided pursuant to the EPA’s request for all documents related to determining the volume of the discharge. When the now-former Vice President of Engineering was contacted by criminal prosecutors, it was discovered that he


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prepared the analysis on his own and that it was not done as part of Summit’s legal defense or at the direction of counsel such that it should have been claimed as privileged.

After calculating that the spill was of longer duration and volume, the Vice President told others in the company including the Chief Operating Officer that there was compelling data that the spill started in August and that the total volume could be much higher than what was being reported to the federal and state authorities. The Chief Operating Officer had seen the location of

the burst pipe after the leak was stopped and stated that it did not seem possible that the leak was larger than what was reported. The Vice President expressed concern that what Summit was reporting could result in legal problems. Both corporate officers believed that the report was preliminary and would be updated, though that never occurred. The Vice President’s calculations, which were shared at the time with corporate leadership, conflicted with Summit’s position after the spill. The Vice President’s calculations, however, are consistent with those in this Joint Factual Statement and would have been highly relevant at the time to determining what type of response should be mounted by federal authorities.

North Dakota’s federally authorized state program under the Clean Water Act mandates that not only must “[a]ny spill or discharge of waste which causes or is likely to cause pollution of waters of the state … be reported immediately” but also that “[t]he owner, operator, or person responsible for a spill or discharge must notify the department as soon as possible … and provide all relevant information about the spill.” Summit did not share the Vice President’s spill volume calculations or estimate that the spill started in August to the State of North Dakota or to federal environmental authorities.

In pleading guilty, Defendant Summit admits that it did not immediately report the discharge of oil into U.S. waters on January 6, 2015, and that the failure to report was knowing. Summit also acknowledges in pleading guilty that its statements and omissions were misleading and failed to provide of all of the information in its possession. Defendant further acknowledges it failed to report and forthrightly report the discharge of oil to federal authorities in telephone calls made on January 7, 18, and 21, 2015, even though federal authorities specifically requested information about the volume of the discharge in each call.

Environmental Impact

Criminal charges under the Clean Water Act and Oil Pollution Act of 1990 do not require proof of environmental harm. Nevertheless, as part of its guilty plea, Summit acknowledges that there was environmental harm caused by the spill.

On January 7, 2015, the day the spill was reported, three water samples were taken from Blacktail Creek, which showed chloride levels of 91,971 milligrams per liter (mg/l), 53,983 mg/l, and 79,975 mg/l. A fourth sample taken from the Little Muddy River at its confluence with Blacktail Creek showed chloride levels of 76,976 mg/l. Based on North Dakota Water Quality Standards, the maximum limit for chloride in Blacktail Creek and the Little Muddy River is 250 mg/l.


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A study conducted by the U.S. Geological Survey on the environmental impacts of the spill and published in a peer-reviewed scientific journal in 2017, found, among other things:

–Elevated levels of sodium, chloride, bromium, strontium, barium, lithium, ammonia, and hydrocarbons downstream of the spill location, including elevated levels of chlorine and sodium in the Little Muddy River, approximately 22.9 km downstream of the spill location;

–In February 2015, chloride levels measured in Blacktail Creek were up to 72 times higher than the expected natural background level; and

–At least through June 2015, impacts of the spill included reduced fish survival rates (2.5% survival at 7.1 km downstream of the spill location, as compared to 89% at an upstream reference site that was unimpacted by the spill).

In addition to its impacts on surface waters, the spill travelled subsurface through soil and groundwater beneath approximately 60 acres of land, causing extensive contamination to groundwater, including Class I groundwater. Groundwater is classified as Class I if it is highly vulnerable to contamination and is an irreplaceable source of drinking water and/or ecologically vital. The contamination included chloride and hydrocarbon levels above state water quality standards. Groundwater recovery operations are still ongoing, under state oversight. An estimated 2,700 acres or more in and around Blacktail Creek have been impacted by the spill or measures taken to clean up the spill.

Remedial Measures

Under the Oil Pollution Act of 1990, responsible parties are encouraged to initiate (directly or with contractors) and pay for cleanup and remediation. Failure to do so will result in the government undertaking the cleanup and billing the responsible party for the amount expended by the Oil Spill Liability Trust Fund established by Congress.

Summit undertook cleanup and remediation measures for the spill and represents that it has spent more than $50 million, approximately $26 million of which was reimbursed by insurance. Summit’s remediation efforts to mitigate the environmental impact of the spill include: removal of contaminated surface water, collection of oil and hydrocarbons from the affected area, removal of contaminated soil, soil and land remediation, and ongoing groundwater monitoring. The cleanup has included the removal of 2 million barrels of surface and groundwater from Blacktail Creek and the surrounding watershed and removal of many tons of contaminated soil. Summit is continuing to monitor and clean the groundwater and anticipates that these efforts will be necessary throughout the period of probation.

Summit no longer has the same owners, leadership, board of directors, or corporate officers that it did at the time of the environmental crimes set forth in the Criminal Information and this Joint Factual Statement. Summit was part of a group of entities that include Summit Midstream Partners, LP (SMLP), a publicly-traded limited partnership. Those who owned the entities at the time of the spill sold their share of the entities, including Summit, to new owners in May 2020. The new ownership purchased Summit knowing of its potential liability related to this


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matter and have installed new management. SMLP now owns and controls Summit and under the terms of the Plea Agreement will guarantee that funding of all remedial measures and all measures necessary to comply with the law.

In pleading guilty, the current senior management of Summit and SMLP are acknowledging that the facts of this case involve serious criminal conduct. Summit and SMLP accept full responsibility for the violations of federal environmental law set forth herein.

Summit has made its new environmental managers available to the government and provided details regarding the various steps it has made to prevent future leaks and to promptly identify and remedy any future problems. These efforts have involved changes to Summit’s corporate structure, management changes, internal reporting mechanisms, and technical improvements. Summit’s new management has made books and records available concerning limits on its ability to pay more in civil penalties and criminal fines.

Since acquiring Summit, Summit and SMLP have designated a Chief Compliance Officer who reports on compliance issues to the Board of Directors, which now also includes an Audit Committee of independent directors.

Summit has established a Summit Operations Control Center (SOCC) that continuously monitors all pipelines operated by Summit or Summit-related entities at all times, including the Marmon System. Had the SOCC been operational at the time of the spill, it should have identified the leak and its location as soon as the leak began, in close to real time. Additionally, Summit represents that certain segments of the Marmon System have been replaced with upgraded pipe, and other equipment. Summit also represents that it has enhanced its physical pipeline inspection procedures in North Dakota.

Summit has implemented a standardized incident reporting tool requiring each environmental incident to be reported and tracked through its control center. Summit has also represented that it has provided training for those in the field along with clear reporting protocols and implemented required annual training of its Environmental Management System (“EMS”). A hotline supervised by the Chief Compliance Officer has been established and allows employees and others to anonymously submit telephone, website, and written submissions of legal, compliance, and environmental concerns, or any violation of Summit’s Code of Business Conduct and Ethics. The existence of the hotline is a subject of regular training and safety meetings.

Additionally, under the terms of the civil Consent Decree, Summit has made commitments to undertake additional remedial measures, including further improvements to its oversight and compliance structure. Compliance with the remedial measures set forth in the civil Consent Decree, including assessment of their implementation by independent third-party auditors and inspectors when called for by the terms of the civil Consent Decree, is a requirement during the three-year period of probation.


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For the United States:

JEAN E. WILLIAMS

U.S. Department of Justice

Deputy Assistant Attorney General Environment &

Nicholas W. Chase

Natural Resources Division

Acting United States Attorney

By:

/s/ Richard A. Udell

By:

/s/ Gary L. Delorme

Richard A. Udell

Gary L. Delorme

Senior Litigation Counsel

Assistant United States Attorney

Environmental Crimes Section

By:

/s/ Christopher J. Costantini

Christopher J. Costantini

Senior Trial Attorney

By:

/s/ Stephen J. Foster

Stephen J. Foster

Trial Attorney

By:

/s/ Erica H. Penack

Erica H. Penack

Trial Attorney


Case 1:21-cr-00152-DMT Document 2 Filed 08/05/21 Page 17 of 17

For the Defendant. Summit Midstream Partners, LLC:

As the authorized representative of Defendant Summit Midstream Partners LLC, I have read this Joint Factual Statement and carefully discussed every part of it with criminal defense counsel for Summit Midstream Partners LLC. I hereby stipulate that this above Joint Factual Statement is true and accurate to the best of my knowledge, and that had the matter proceeded to trial, the United States would have proved the same beyond a reasonable doubt.


/s/ James D. Johnson			8-4-2021
James D. Johnson			Date
Authorized Representative
Summit Midstream Partners LLC

I am counsel for Summit Midstream Partners LLC. I have carefully discussed every part of this Joint Factual Statement with the authorized representatives of Summit Midstream Partners LLC. To the best of my knowledge this is a true and accurate factual statement, and had the matter proceeded to trial, the United States would have proved the same beyond a reasonable doubt. This statement provides a sufficient factual basis for charges set forth in the Criminal Information and Summit Midstream Partners LLC's guilty pleas as set forth in the Plea Agreement.


/s/ Cliff Stricklin			8-4-2021
Cliff Stricklin, Counsel			Date

Document


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 1 of 14

UNITED STATES DISTRICT COURT DISTRICT OF NORTH DAKOTA

UNITED STATES OF AMERICA,

Case No.

1:21-cr-00152

https://cdn.kscope.io/e23a2df3d4766ac41f156badbb5cd611-image_01.jpg

SUMMIT MIDSTREAM PARTNERS, LLC,

Defendant.

CRIMINAL PLEA AGREEMENT

The United States of America, by and through the United States Attorney for the District of North Dakota, and the Environmental Crimes Section of the United States Department of Justice and undersigned counsel (collectively referred to herein as the “government”), and Defendant, Summit Midstream Partners, LLC, by and through their authorized representatives and undersigned counsel, hereby enter into the following Plea Agreement (“Agreement”) pursuant to Rule 11(c)(1)(C) of the Federal Rules of Criminal Procedure:

1.Waiver of Indictment and Criminal Charges. Defendant, having been advised

through its representative and counsel of the charges and the right to be charged by Indictment, hereby agrees to waive that right and enter pleas of guilty to the charges brought by the government in the Criminal Information filed against it in the District of North Dakota and as set forth below. The guilty plea is to be entered by Defendant through a senior corporate officer acceptable to the government who is authorized by resolutions by Defendant, and Defendant’s parent corporation, Summit Midstream Partners, LP (“SMLP”), to enter pleas of guilty on Defendant’s behalf and to appear and represent Defendant at the plea hearing and at the sentencing hearing in the District of North Dakota. Defendant has proposed and the government has agreed that James D. Johnston, Executive Vice President, General Counsel, Chief Compliance Officer and Secretary, will be the corporate officer that will enter the guilty plea and be present for sentencing on behalf of Defendant.


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2. Defendant’s Admission of Guilt. Defendant is pleading guilty because it is guilty

and wishes to acknowledge its acceptance of responsibility for the criminal conduct described herein. In pleading guilty, Defendant agrees that the Joint Factual Statement that appears as Attachment A to this Agreement is a true and accurate statement of its criminal conduct and

provides a sufficient factual basis for the pleas. If the Court rejects this Agreement and Defendant withdraws its plea, then the Statement of Facts, Criminal Information, Plea Agreement, and all other statements made during a proceeding under Federal Rule of Criminal Procedure 11, or during plea discussions, will not be admissible against Defendant. Defendant further understands that if the Court refuses to accept any provision of this Agreement, neither party shall be bound by the provisions of the Agreement.

3. Pursuant to this Agreement and consistent with the Joint Factual Statement,

Defendant agrees to enter pleas of guilty to and accepts responsibility for the following charges:

Count 1 (Negligent Discharge of a Harmful Quantity of Oil): From on or about August 17,

2014, through and including on or about January 6, 2015, in the District of North Dakota and elsewhere, the Defendant negligently discharged and caused the negligent discharge of a harmful quantity of oil into the navigable waters of the United States, specifically approximately 700,000 barrels (approximately 29.4 million gallons) of oil-contaminated produced water from its pipeline, in violation of the Clean Water Act, as amended by the Oil Pollution Act of 1990, Title 33, United States Code, Sections 1319(c)(1)(A), 1321(b)(3).

Count 2 (Knowing Failure to Immediately Report a Discharge of Oil): From on or about

January 6, 2015, through and including, but not limited to, January 21, 2015, in the District of


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North Dakota and elsewhere, the Defendant knowingly failed to immediately report, and knowingly caused the failure to immediately report the discharge of a harmful quantity of oil into and upon the navigable waters of the United States, in violation of Title 33, United States Code, Section 1321(b)(5).

4.Elements of the Offenses: Defendant understands and agrees to the elements of the

offenses:

a.Count 1 (Negligent Discharge of a Harmful Quantity of Oil):

(1)Defendant, a person, discharged and caused the discharge;

(2)Of a harmful quantity of oil;

(3)Into and upon the navigable waters of the United States;

(4)Defendant acted negligently; and

(5)Defendant’s negligence was a proximate cause of the discharge.

b.Count 2 (Knowing Failure to Immediately Report a Discharge of Oil):

(1)Defendant, a person;

(2)In charge of the Marmon Water Gathering System, an onshore facility;

(3)From which a harmful quantity of oil was discharged;

(4)Into and upon the navigable waters of the United States;

(5)Knowingly;

(6)Failed to immediately report the discharge of the harmful quantity of oil into the navigable waters to the National Response Center.

5.Maximum Penalties. Defendant understands that the maximum applicable

statutory penalties for the counts to which it is pleading are:


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Count 1: A maximum fine of either $3,375,000 ($25,000 per day times 135 days of

violation) pursuant to the Clean Water Act, 33 U.S.C. 1321(c)(1)(B), or twice the gross gain or loss resulting from the unlawful conduct, pursuant to the Alternative Fines Act,18 U.S.C. § 3571(c) and (d); a term of probation of five years, pursuant to 18 U.S.C. § 3561(c)(2); and a special assessment of $125, pursuant to 18 U.S.C. § 3013(a)(1)(B)(iii). Defendant understands that, in addition to any other penalty, the Court may order the payment of restitution to any victim of the offenses pursuant to the provisions of 18 U.S.C. § 3663.

Count 2: A maximum fine of either $500,000, or twice the gross pecuniary gain or loss

resulting from the unlawful conduct, pursuant to 18 U.S.C. § 3571(c) and (d); a term of probation of five years, pursuant to 18 U.S.C. § 3561(c)(1); and a special assessment of $400, pursuant to 18 U.S.C. § 3013(a)(2)(B). Defendant further understands that, in addition to any other penalty, the Court may order the payment of restitution to any victim of the offenses pursuant to the provisions of 18 U.S.C. § 3663.

6.Rights Waived by Pleading Guilty. Defendant understands that by pleading guilty,

it surrenders certain rights, including the right to a speedy public jury trial and related rights as follows:

a.A jury would be composed of twelve lay persons selected at random. Defendant and Defendant’s attorney would help choose the jurors by removing prospective jurors “for cause,” where actual bias or other disqualification is shown; or by removing jurors without cause by exercising so-called peremptory challenges. The jury would have to agree unanimously before it could return a verdict. The jury would be instructed that Defendant is presumed innocent and that it could not return a guilty verdict unless it found Defendant guilty beyond a reasonable doubt.

b.If a trial were held without a jury, then the Court would find the facts and determine whether Defendant was guilty beyond a reasonable doubt.

c.At a trial, whether by a jury or Court, the United States is required to present witness testimony and other evidence against Defendant. Defendant’s


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attorney can confront and examine them. In turn, the defense can present witness testimony and other evidence. If witnesses for Defendant refuse to appear voluntarily, Defendant can require their attendance through the subpoena power of the Court.

Defendant understands that by pleading guilty, it is giving up all of the rights set forth above, and that there will be no trial. Defendant’s attorney has explained these rights, and consequences of Defendant’s waiver.

7.Applicability of Sentencing Guidelines. Defendant understands and acknowledges

that, at sentencing, the Court is required to consider the United States Sentencing Guidelines (“U.S.S.G.”), together with the other sentencing principles set forth in Title 18, United States Code, Section 3553(a). Defendant understands and acknowledges that the U.S.S.G., including Chapter Eight that provides guidance for the sentencing of corporate defendants, will be considered by the Court, except that pursuant to U.S.S.G. §§ 8C2.1 and 8C2.10, the U.S.S.G. that pertain to the sentencing of organizations do not determine the fine range in cases involving environmental crimes or obstruction of justice. Instead, the fine is to be determined under 18 U.S.C. §§ 3553 and 3571. All other sections of Chapter Eight of the U.S.S.G. that are applicable to corporate defendants are applicable to this case, including provisions for probation.

8.Statute of Limitations. Defendant’s pleas will be tendered pursuant to Rule

11(c)(1)(C) of the Federal Rules of Criminal Procedure. Accordingly, if the sentencing judge rejects this Plea Agreement, or if Defendant breaches any of the terms of this Plea Agreement, Defendant hereby waives any defense to any charges that it might otherwise have under any statute of limitations, pre-indictment delay, or the Speedy Trial Act for 120 days following any nullification or voiding of this Plea Agreement, except to the extent that such defenses existed as of the date of the signing of this Plea Agreement.

9.Corporate Authorization. Defendant represents that it is authorized to enter into this


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Plea Agreement. At the time of signing, Defendant shall provide to the United States a written corporate resolution, to be filed with the U.S. District Court, in the form of notarized legal documents certifying that Defendant is authorized to enter into and comply with all of the provisions of this Plea Agreement. The resolutions further shall certify that Defendant SMLP, Defendant’s parent corporation; and Meadowlark Midstream, LLC (“Meadowlark”), the subsidiary of SMLP that owns and operates the Marmon Water Gathering System, have authorized these actions, and that all corporate formalities for such authorizations have been observed.

10.Parties Bound and Non-Prosecution of Other Offenses. This Plea Agreement is

binding only upon the United States Attorney for the District of North Dakota and the Environmental Crimes Section of the Department of Justice. As part of this Agreement and solely because of the promises made by Defendant in this Agreement, the United States Attorney’s Office for the District of North Dakota and the Environmental Crimes Section agree to forgo additional criminal prosecution against Defendant, SMLP and SMLP’s owned and operated entities, including but not limited to Meadowlark, Summit Midstream Holdings, LLC, and Summit Midstream GP, LLC, in the District of North Dakota for any of the offenses set forth in the pending Criminal Information or for any other related offenses that are known to the government at the time of the signing of this Agreement. Defendant understands and agrees that neither this paragraph nor this Agreement limits the prosecuting authority of any other sections or divisions of the Department of Justice, including the United States Attorney of any other judicial district, or any other federal, state, or local regulatory or prosecuting authorities. Furthermore, this Agreement does not provide or promise any waiver of any civil or administrative actions, sanctions, or penalties that may apply, including but not limited to: fines; penalties; claims for damages to natural resources; suspension ; debarment; listing to restrict


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rights and opportunities of Defendant to contract with or receive assistance, loans, and benefits from United States agencies; licensing; injunctive relief; or remedial action to comply with any applicable regulatory requirement. This Agreement applies only to federal crimes committed by Defendant and the related listed entities and has no effect on any proceedings against any defendant not expressly mentioned herein, including the criminal liability of any individuals. Defendant further understands the United States Attorney’s Office and the Environmental Crimes Section reserve the right to inform and/or respond to inquiries from any local, state, or federal agency. The Environmental Crimes Section of the Department of Justice will bring this Agreement and factual information concerning the conduct and cooperation of the Defendant and its related entities to the attention of any other prosecuting authorities or agencies, as well as debarment authorities if requested.

11.Sentencing Agreement. Pursuant to Rule 11(c)(1)(C) of the Federal Rules of

Criminal Procedure, and specifically pursuant to 18 U.S.C. § 3571(d), and in return for the complete fulfillment by Defendant of all of its obligations under this Agreement, the Parties agree that the sentence to be imposed by the Court includes a total monetary penalty consisting of

$15,000,000, plus mandatory special assessments. The parties agree and stipulate that these amounts are consistent with 18 U.S.C. § 3571.

a.Criminal Fine. For Count 1, the parties agree to a fine of $14,500,000, pursuant to the

alternative fine provision of 18 U.S.C. § 3571(d) (up to twice the gross gain or loss). For Count 2, the parties agree to a fine of $500,000.

b.Mandatory Special Assessment. Defendants shall pay a special assessment of $125 for

Count 1 and $400 for Count 2. The total amount of special assessments is $525.


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 8 of 14

c.Payments. Defendant agrees that if the terms of this Rule 11(c)(1)(C) Plea Agreement

are accepted by the Court, special assessments shall be paid on the day of sentencing. Payment is to be made in the form of a check payable to “United States District Court Clerk.” The fine is payable as follows, unless Defendant pays earlier: $3,000,000 shall be paid on the first through the fourth anniversary of the date of sentencing. The final payment shall be due not later than 90 days prior to fifth anniversary of the date of sentencing. Defendant understands that it will remain on probation beyond the minimum three-year period agreed to herein unless and until all payments are made, or as may be ordered by the Court. Notwithstanding any other provision of 18 U.S.C. § 3612, Defendant agrees that interest shall start to accrue on any unpaid balance on the day following sentencing and that the provisions regarding collection, interest, and penalties set for in 18 U.S.C. §§ 3572(h), (i), and 3612 shall apply. Payment is to be made by or on behalf of Defendant in the form of a check payable to “United States District Court Clerk.” Defendant will not be assessed any financial penalty for early payment of the fine.

d.Probation. Defendant will be placed on organizational probation for a minimum period

of three years from the date of sentencing pursuant to 18 U.S.C. § 3561(c)(1) and

U.S.S.G. §§ 8D1.1 and 8D1.2. The terms of probation shall include the following specific provisions, in addition to the Court’s standard conditions:

i.No Further Violations. Defendant agrees that it will commit no further

violations of federal, state and local environmental laws.

ii.Payments. Payment in full of the monetary amounts set forth herein

including all special assessments, fines and restitution.


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 9 of 14

iii.Environmental Compliance. Consistent with the sentencing polices set forth

in U.S.S.G. § 8D1.4, Defendant agrees to the following Special Conditions of Probation and further understands and agrees that any violation of these Special Conditions of Probation may constitute grounds for revocation of probation:

(1)Defendant shall fully fund and implement the remedial measures set forth in the civil Consent Decree entered into by Defendant and the Department of Justice and the State of North Dakota (“Consent Decree”), attached hereto as Attachment C, including General Compliance Requirements (Section IX), Specific Compliance Requirements (Section X), and Remediation Measures (Section XI).

(2)Defendant and its parent corporation, SMLP, further agree to implement the remedial measures set forth in the civil Consent Decree to all related entities and pipelines that transport produced water.

(3)Defendant shall establish and administer a system that enables employees and contractors to report, anonymously if they wish, any concerns relating to non-compliance with applicable environmental laws or regulations, provisions of this Plea Agreement, the Consent Decree, or the Environmental Management System (defined in Paragraph IV.8.l. of the Consent Decree). Defendant shall promptly review, investigate, and document concerns raised in such reports, and shall initiate, monitor, and document all actions taken as a result of such reports. Defendant shall submit to the Office of Probation and the United States a quarterly report providing all such open reports, all


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 10 of 14

investigative reports into such allegations, and actions taken as a result of such reports. Defendant agrees not to retaliate against any individual on the basis of their making such a report.

(4) In addition to the requirements of federal, state, and local laws and regulations governing the immediate reporting of spills, releases, or discharges, if requested by the United States, Defendant shall provide any and all information it has regarding the quantity, characteristics, and cause of any such spills, releases, or discharges, regardless of whether this information is specifically required by law.

(5)Defendant and all related entities involved in the transportation of produced water shall notify the United States within 14 days of acquisition or assumption of operation, monitoring, maintenance, or management of any produced water pipeline, and within 14 days of removing any produced water pipeline from any entity owned or operated by Defendant, SMLP and SMLP’s owned and operated entities, including but not limited to Meadowlark, Summit Midstream Holdings, LLC, and Summit Midstream GP, LLC.

(6)Any reports or notifications required by the Consent Decree or this Agreement shall be submitted simultaneously via electronic means by Defendant to the Office of Probation and all undersigned government counsel.

12.Breach by the Defendant. Defendant acknowledges and understands that if

Defendant violates any term of this Plea Agreement, engages in any further criminal activity, or


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 11 of 14

fails to appear for sentencing, the United States will be released from its commitments. In that event, this Plea Agreement shall become null and void at the discretion of the United States, and Defendant will face the following consequences: (1) all information Defendant has provided at any time to attorneys, employees, or law enforcement officers of the government, to the Court, or to the federal grand jury, may be used against Defendant in any prosecution or proceeding; and (2) the United States will be entitled to seek additional charges against Defendant or any related entity and to use any information obtained directly or indirectly from Defendant in those additional prosecutions. Nothing in this Agreement prevents the United States from prosecuting Defendant for perjury, false statement(s), or false declaration(s), if Defendant commits such acts in connection with this agreement.

13.Waiver of Appeal. Defendants ordinarily have a right to appeal their conviction and

sentence (“Judgment”), unless otherwise agreed. Appeals are taken to the United States Court of Appeals for the Eighth Circuit, pursuant to Title 18, United States Code, Section 3742(a). The Court of Appeals has ruled that defendants can waive (give up) their right to appeal. Defendants often waive their right to appeal as part of a plea agreement and in exchange for concessions by the United States. Defendant understands that the government will seek to enforce such waivers. Defendant and Defendant’s attorney further acknowledge they have fully reviewed and fully discussed the record in this case and all issues that may be raised on appeal. They have fully discussed Defendant’s right of appeal and the consequences of waiver. Defendant has decided to waive any right of appeal, except as may be provided herein.

By signing this Plea Agreement, Defendant voluntarily waives Defendant’s right to appeal the Court’s Judgment against Defendant; and, absent a claim of ineffective assistance of counsel,


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 12 of 14

Defendant waives all rights to contest the Judgment in any post-conviction proceeding, including one pursuant to Title 28, United States Code, Section 2255.

Defendant understands that the United States was motivated by Defendant’s willingness to waive any right of appeal when the United States chose to offer Defendant terms of a plea agreement. In other words, the United States was willing to offer certain terms favorable to Defendant in exchange for finality. Defendant understands and agrees this case will be over once Defendant has been sentenced by the Court. Defendant agrees that it will be a breach of this Agreement if Defendant appeals in violation of this Agreement. The United States will rely upon Defendant’s waiver and breach as a basis for dismissal of the appeal. Defendant agrees an appeal in violation of this Agreement should be dismissed.

By signing this Plea Agreement, Defendant further specifically waives Defendant’s right to seek to withdraw Defendant’s plea of guilty, pursuant to Federal Rules of Criminal Procedure 11(d), once the plea has been entered in accordance with this Agreement. The appellate court will enforce such waivers. Defendant agrees that any attempt to withdraw Defendant’s plea will be denied and any appeal of such denial should be dismissed.

14.Defendant acknowledges reading and understanding all provisions of the Plea Agreement. Defendant and Defendant’s attorneys have discussed the case and reviewed the Plea Agreement. They have discussed Defendant’s constitutional and other rights, including, but not limited to, Defendant’s plea-statement rights under Rule 410 of the Federal Rules of Evidence and Rule 11(f) of the Federal Rules of Criminal Procedure.

AGREED:


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 13 of 14

For the United States;

JEAN E. WILLIAMS

Nicholas W. Chase

Deputy Assistant Attorney General

Acting United States Attorney

Environment & Natural Resources Division

U.S. Department of Justice

By:

/s/ Richard A. Udell

By:

/s/ Gary L. Delorme

Richard A. Udell

Gary L. Delorme

Senior Litigation Counsel

Assistant United States Attorney

Environmental Crimes Section

By:

/s/ Christopher J. Costantini

Christopher J. Costantini

Senior Trial Attorney

By:

/s/ Stephen J. Foster

Stephen J. Foster

Trial Attorney

By:

/s/ Erica H. Penack

Erica H. Penack

Trial Attorney


Case 1:21-cr-00152-DMT Document 4 Filed 08/05/21 Page 14 of 14

For the Defendant, Summit Midstream Partners. LLC:

1 have been authorized by a corporate resolution of Defendant Summit Midstream Partners LLC , and its parent corporation, Summit Midstream Partners LP, to sign this Plea Agreement. Summit Midstream Partners LLC has been advised by its attorneys of its rights, of possible defenses, of the Sentencing Guideline provisions, and of the consequences of entering into this Plea Agreement. Summit Midstream Partners LLC voluntarily agrees to all of the terms of this Plea Agreement. Summit Midstream Partners LP has authorized me further to obligate it to guarantee all payments and the terms of the remedial measures required by this agreement. No promises or inducements have been made to Summit Midstream Partners, LLC other than those contained in this Plea Agreement. Defendant Summit Midstream Partners LLC is satisfied with the representation of its attorneys in this matter.


/s/ James D. Johnson			8-4-2021
James D. Johnson			Date
Authorized Representative
Summit Midstream Partners LLC

1 am counsel for Defendant Summit Mid stream Partner L , and for its parent corporation, Summit Midstream Partners LP. I have carefully discussed every part of this Plea Agreement the authorized representatives of Defendant, and its parent corporation. I have fully advised the authorized representatives of Summit Midstream Partners LLC of its rights, of possible defenses, of the Sentencing Guidelines' provisions, and of the consequences of entering into this Plea Agreement. To my knowledge, the decision of Summit Midstream Partners LLC to enter into this Plea Agreement is informed and voluntary.


/s/ Cliff Stricklin			8-4-2021
Cliff Stricklin, Counsel			Date

Document

IN THE UNITED STATES DISTRICT COURT DISTRICT OF NORTH DAKOTA

WESTERN DIVISION

UNITED STATES OF AMERICA, and the STATE OF )

NORTH DAKOTA, NORTH DAKOTA DEPARTMENT )

OF ENVIRONMENTAL QUALITY and NORTH )

DAKOTA GAME AND FISH DEPARTMENT, )

) Civil Action No.

Plaintiffs, )

)

v. )

)

SUMMIT MIDSTREAM PARTNERS, LLC and )

MEADOWLARK MIDSTREAM COMPANY, LLC, )

)

Defendants )

CONSENT DECREE

TABLE OF CONTENTS

I.INTRODUCTION 1

II.JURISDICTION AND VENUE 3

III.APPLICABILITY 4

IV.DEFINITIONS 5

V.STATEMENT OF PURPOSE 11

VI.CIVIL PENALTY 12

VII.CERTIFICATION 17

VIII.NATURAL RESOURCE DAMAGES 17

IX.GENERAL COMPLIANCE REQUIREMENTS 19

X.SPECIFIC COMPLIANCE REQUIREMENTS. 21

A.Pipeline Installation, Operation, and Testing 21

B.Control Room and Computational Pipeline Monitoring System 25

C.Line Visibility and Inspection 26

D.Spill Response Planning and Countermeasures 28

E.Environmental Management System 30

F.Data Management 32

G.Training 33

H.Requirements for Third-Party Inspectors and Third-Party Auditors 34

XI.REMEDIATION MEASURES 37

XII.REPORTING REQUIREMENTS 39

XIII.STIPULATED PENALTIES 43

XIV.FORCE MAJEURE 47

XV.DISPUTE RESOLUTION 49

XVI.INFORMATION COLLECTION AND RETENTION; ACCESS TO PROPERTIES 52

XVII.EFFECT OF SETTLEMENT 54

XVIII.RESERVATION OF RIGHTS BY THE PLAINTIFFS 56

XIX.COVENANTS BY DEFENDANTS. 57

XX.COSTS 58

XXI.NOTICES AND SUBMISSIONS. 58

XXII.RETENTION OF JURISDICTION 61

XXIII.MODIFICATION 61

XXIV.TERMINATION 61

XXV.PUBLIC PARTICIPATION 63

XXVI.SIGNATORIES/SERVICE 63

XXVII.INTEGRATION 64

XXVIII.APPENDICES 64

XXIX.26 U.S.C. SECTION 162(F)(2)(A)(II) IDENTIFICATION 64

XXX.FINAL JUDGMENT 65

I.INTRODUCTION

A.Concurrent with the lodging of this Consent Decree, Plaintiffs, the United States of America, on behalf of the United States Environmental Protection Agency (“EPA”) and the United States Department of the Interior (“DOI”), and the State of North Dakota (the “State”), on behalf of the North Dakota Department of Environmental Quality (“NDDEQ”) and the North Dakota Game and Fish Department (“NDGF”), have filed a complaint against Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC the (“Complaint Defendants”) relating to the discharge of produced water, including crude oil, reported on January 7, 2015, approximately 1.2 miles northeast of Marmon, North Dakota, into Blacktail Creek from a ruptured pipeline owned and operated by the Complaint Defendants (the “Blacktail Creek Discharge”).

B.The Complaint includes claims against the Complaint Defendants for injunctive relief under the Clean Water Act (“CWA”) Section 309(b), 33 U.S.C. § 1319(b), and N.D.C.C.

§ 61-28-08(5); and civil penalties under CWA Section 311(b), 33 U.S.C. § 1321(b), and

N.D.C.C. § 61-28-08(4), for violations of: CWA Section 301(a), 33 U.S.C. § 1311(a); CWA Section 311(b)(3), 33 U.S.C. § 1321(b)(3); N.D.C.C. § 61-28-06 and N.D. Admin. Code §§ 33- 16-02.1-08, 33-16-02.1-09, and 33-16-02.1-11(2); N.D. Admin. Code § 33-16-02.1-11(4).

C.The Complaint also includes claims against Complaint Defendants under CWA Section 311(f)(4), 33 U.S.C. § 1321(f)(4), and N.D.C.C. § 61-28-04(24), for damages for injury to, destruction of, or loss of natural resources, and costs of natural resource damage assessment and restoration actions that Plaintiffs have incurred or will incur at or in connection with the Blacktail Creek Discharge.

D.DOI, through the United States Fish and Wildlife Service, has been delegated

authority to act as Federal Trustee for natural resources impacted by the Blacktail Creek Discharge pursuant to the National Contingency Plan, 40 C.F.R. Part 300. The Governor of the State of North Dakota has designated NDDEQ and NDGF to serve as State Trustees pursuant to 40 C.F.R. § 300.605. The Trustees’ responsibilities include the assessment and recovery of damages for injuries to natural resources from the Blacktail Creek Discharge and use of the recovered damages to restore, replace, rehabilitate, or acquire the equivalent of the injured natural resources and associated natural resource services.

E.Investigations conducted by the Trustees have identified elevated levels of pollutants in surface water downstream of the ruptured pipeline for approximately 4.5 miles of Blacktail Creek and 28 miles of the Little Muddy River downstream of its confluence with Blacktail Creek. The Trustees have determined that the Blacktail Creek Discharge and related remediation efforts have impacted natural resources, including but not limited to aquatic, riparian, and upland habitat.

F.The United States and the State have worked closely together in developing the measures included in this Consent Decree, which are designed to remedy the harm caused by the spill and prevent future violations of the Clean Water Act.

G.On June 19, 2015, the North Dakota Industrial Commission (“NDIC”) brought an administrative action against the Complaint Defendants relating to the Blacktail Creek Discharge. Concurrently with this Consent Decree, NDIC and the Complaint Defendants will enter into a separate Consent Agreement that resolves NDIC’s administrative action. The Consent Agreement incorporates all terms of this Consent Decree. In addition, requirements in Section X.A, Paragraph 35 (Existing Pipelines), and Section XII, Paragraph 72.a(3) (Annual Reports) will remain in effect as part of the Consent Agreement after this Consent Decree is

terminated.

H.Summit Operating Services Company, LLC is included as a defendant to this Consent Decree because it supplies all employees necessary for implementation of injunctive relief measures at Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC’s facilities, and is responsible for managing operation of those facilities. Summit Midstream Partners, LLC; Meadowlark Midstream Company, LLC; and Summit Operating Services Company, LLC are collectively referred to as “Defendants” in this Consent Decree.

I.The United States and the State have reviewed Financial Information provided by Defendants and have determined that Defendants have limitations on their ability to pay a civil penalty.

J.Defendants do not admit any liability to the United States or the State arising out of the transactions or occurrences alleged in the Complaint.

K.The Parties recognize, and the Court by entering this Consent Decree finds, that this Consent Decree has been negotiated by the Parties in good faith and will avoid litigation among the Parties and that this Consent Decree is fair, reasonable, and in the public interest.

NOW, THEREFORE, with the consent of the Parties, IT IS HEREBY ADJUDGED, ORDERED, AND DECREED as follows:

II.JURISDICTION AND VENUE

1.This Court has jurisdiction over the subject matter of this action pursuant to

28 U.S.C. §§ 1331, 1345, and 1355, and Sections 309(b), 311(b)(7)(E), and 311(n) of the Clean Water Act, 33 U.S.C. §§ 1319(b), 1321(b)(7)(E), 1321(n). This Court has supplemental jurisdiction over the State law claims asserted by the State of North Dakota pursuant to 28

U.S.C. § 1367. This Court has jurisdiction over Summit Operating Services Company, LLC’s

obligations in this Consent Decree pursuant to the All Writs Act, 28 U.S.C. § 1651, and Fed. R. Civ. P. 19(a).

2.Venue lies in this District pursuant to Sections 309(b) and 311(b)(7)(E) of the CWA, 33 U.S.C. §§ 1319(b) and 1321(b)(7)(E), and 28 U.S.C. §§ 1391 and 1395, because it is the judicial district in which Defendants are doing business and in which the claims alleged in the Complaint occurred. For purposes of this Decree, or any action to enforce this Decree, Defendants consent to the Court’s jurisdiction over this Decree and any such action and over Defendants, and consent to venue in this judicial district.

3.For purposes of this Consent Decree, Defendants agree that the Complaint states claims upon which relief may be granted pursuant to Sections 309(b), 311(b), and 311(f)(4) of the CWA, 33 U.S.C. §§ 1319(b), 1321(b), 1321(f)(4); and N.D.C.C. §§ 61-28-06, 61-28-08(5), 61-28-08(4), 61-28-04(24).

III.APPLICABILITY

4.The obligations of this Consent Decree apply to and are binding upon the United States and the State, and upon Defendants and any successors, assigns, or other entities or persons otherwise bound by law.

5.No transfer of ownership or operation of any Pipeline Facility, whether in compliance with the procedures of this Paragraph or otherwise, shall relieve Defendants of their obligation to ensure that the terms of the Decree are implemented. At least 30 Days prior to such transfer, Defendants shall provide a copy of this Consent Decree to the proposed transferee and shall simultaneously provide written notice of the prospective transfer, together with a copy of the proposed written agreement, to the United States and the State. Any attempt to transfer ownership or operation of a Pipeline Facility without complying with this Paragraph constitutes a

violation of this Decree.

6.Defendants shall provide a copy of this Consent Decree to all officers, employees, and agents whose duties might reasonably include compliance with any provision of this Decree, as well as to any contractor retained to perform work required under this Consent Decree, prior to commencement of any relevant duties or work. Defendants shall condition any such contract upon performance of the work in conformity with the terms of this Consent Decree.

7.In any action to enforce this Consent Decree, Defendants shall not raise as a defense the failure by any of its officers, directors, employees, agents, or contractors to take any actions necessary to comply with the provisions of this Consent Decree.

IV.DEFINITIONS

8.Terms used in this Consent Decree that are defined in the CWA or in regulations promulgated pursuant to the CWA shall have the meanings assigned to them in the CWA or such regulations, unless otherwise provided in this Decree. Whenever the terms set forth below are used in this Consent Decree, the following definitions apply:

a.“Audit Findings” means a written summary of all instances of noncompliance and all areas of concern identified during the course of an audit.

b.“Blacktail Creek Discharge” means the discharge of produced water, including crude oil, from a ruptured pipeline approximately 1.2 miles northeast of Marmon, North Dakota, into Blacktail Creek, reported on January 7, 2015.

c.“Complaint” means the complaint filed by the United States and the State

in this action.

d.“Computational Pipeline Monitoring System” or “CPM System” means a pipeline leak detection system using software-based algorithmic tools, including supervisory

control and data acquisition (“SCADA”), and real-time pipeline monitoring data.

e.“Consent Decree” or “Decree” means this Decree and all appendices attached hereto (listed in Section XXVIII).

f.“Control Room” means any operations center where Pipeline Facilities are remotely monitored, operated, and controlled by personnel using a SCADA system, including the operations center currently located in Houston, Texas.

g.“CPM System and Control Room Auditor” means the third-party auditor approved pursuant to Section X.H and contracted by Defendants to perform the duties set forth in Paragraph 38.

h.“Day” means a calendar day unless expressly stated to be a business day.

In computing any period of time for a deadline under this Consent Decree, where the last day would fall on a Saturday, Sunday, or federal or State holiday, the period runs until the close of business of the next business day.

i.“Defendants” means Summit Midstream Partners, LLC; Meadowlark Midstream Company, LLC; and Summit Operating Services Company, LLC.

j.“DOI” means the United States Department of Interior and any of its successor departments or agencies.

k.“Effective Date” means the date upon which this Consent Decree is entered by the Court or a motion to enter the Consent Decree is granted, whichever occurs first, as recorded on the Court’s docket.

l.“Environmental Management System” or “EMS” means a management system governing the organizational structure, planning activities, responsibilities, practices, processes, and resources for developing, implementing, achieving, reviewing, and maintaining

environmental compliance.

m.“EMS Auditor” means the third-party auditor approved pursuant to Section X.H and contracted by Defendants to perform the duties set forth in Paragraph 53.

n.“EMS Consultant” means the third-party consultant approved pursuant to Section X.H and contracted by Defendants to perform the duties set forth in Paragraphs 51 and 52.

o.“EMS Criteria” means the required EMS elements set forth in Paragraph

50.

p.“EPA” means the United States Environmental Protection Agency and any of its successor departments or agencies.

q.“Existing Pipelines” means Pipelines owned or operated by Defendants as of the Effective Date, as depicted on Appendix A.

r.“Financial Information” means the documents provided by Defendants in response to the information requests identified at Appendix D.

s.“Hydrostatic Test” or “Hydrostatic Testing” means a Pressure Test conducted with water.

t.“Initial EMS Review and Evaluation” means an evaluation of Defendants’ existing environmental management practices pursuant to the requirements of Paragraph 51.

u.“Interest” means interest at the annual rate of 3.25%.

v.“Lead Agency” means the following:

(1)For oversight of Section VI (Civil Penalty) and Section X (Specific Compliance Requirements), EPA and NDDEQ.

(2)For oversight of Section VIII (Natural Resource Damages), the

Trustees.

(3)For oversight of Section XI (Remediation Measures), NDDEQ.

(4)For all other matters, the United States and the State.

w.“Leak Detection Investigation Report” means the report meeting the requirements of Paragraph 47, which documents the results of an investigation into any failure of the CPM System and/or visual inspections to identify a Reportable Discharge.

x.“Management of Change Procedure” means a formal written procedure to manage changes to technology, equipment, or processes in order to control safety, health, and environmental risks.

y.“Maximum Operating Pressure” or “MOP” means a maximum of 80% of the test pressure which was performed on the Pipeline prior to being placed into service, unless a new MOP is set in compliance with Paragraphs 35.b-35.c. The current MOP for each Existing Pipeline is:


Existing Pipeline			Current MOP
Marmon Pipeline			550 psi
Manger Pipeline			550 psi
Bibler Pipeline			550 psi
Oppegaard Pipeline			550 psi
Thomas Pipeline			550 psi
Wood Pipeline			550 psi
Sirtola Pipeline			550 psi

z.“Natural Resource” or “Natural Resources” means land, fish, wildlife, biota, air, water, ground water, drinking water supplies, and other such resources belonging to,

managed by, held in trust by, appertaining to, or otherwise controlled by the United States and/or the State.

aa. “Natural Resource Damages” means any damages recoverable by the United States or the State pursuant to Sections 107(a)(4)(C) and 107(f) of the Comprehensive Environmental Response, Liability, and Compensation Act (“CERCLA”), 42 U.S.C.

§§ 9607(a)(4)(C) and 9607(f); Section 311(f)(4) of the CWA, 33 U.S.C. § 1321(f)(4); Section 1002(b)(2)(A) of the Oil Pollution Act, 33 U.S.C. § 2702(b)(2)(A); and N.D.C.C. § 61-28- 04(24), for injury to, destruction of, loss of, loss of use of, or impairment of natural resources as a result of the Blacktail Creek Discharge. Natural Resource Damages include, but are not limited to: (i) the costs of assessing injury to, destruction of, loss of, loss of use of, or impairment arising from or relating to the Blacktail Creek Discharge; (ii) the costs of restoration, rehabilitation, or replacement of injured or lost natural resources or of acquisition of equivalent resources; (iii) the costs of planning such restoration activities; and (iv) compensation for injury, destruction, loss, loss of use, or impairment of natural resources.

bb. “NDDEQ” means the North Dakota Department of Environmental Quality and any of its successor departments or agencies. NDDEQ is the successor agency of the North Dakota Department of Health’s Environmental Health Section (“NDDH-EHS”). NDDH-EHS’s interest in the causes of action that are the subject of the Complaint was assigned to NDDEQ under 2017 N.D. Sess. Laws ch. 199, § 1.

cc. “NDGF” means the North Dakota Game and Fish Department and any of its successor departments or agencies.

dd. “NDIC” means the North Dakota Industrial Commission and any of its associated departments or agencies.

ee. “NRDAR Fund” means the DOI Natural Resource Damage Assessment and Restoration Fund.

ff. “OQ Qualified” means having received up-to-date training to recognize and react to abnormal operating conditions pursuant to API Covered Task 15.1.

gg. “Paragraph” means a portion of this Decree identified by an Arabic

numeral.

hh. “Parties” means the United States, the State, and Defendants.

ii. “Plaintiffs” means the United States and the State.

jj. “Pipelines” means all produced water pipelines owned and/or operated by Defendants in North Dakota at any time during the Consent Decree term.

kk. “Pipeline Facility” or “Pipeline Facilities” means all produced water pipeline systems in North Dakota owned and/or operated by Defendants at any time during the Consent Decree term, including Pipelines, LACT units, pumps, and associated equipment.

ll. “Pressure Test” means a proof test in which the pipe is pressurized to evaluate its integrity, conducted in accordance with applicable API, ASME, or ASTM guidelines and the Pipeline manufacturer recommendations. In the event of a conflict between any guideline and the applicable Pipeline manufacturer’s recommendations for pressure testing, testing shall conform to the more stringent requirement.

mm. “Reportable Discharge” means any spill or discharge from a Pipeline Facility which is required to be reported under either N.D.A.C. § 33.1-16-02.1-11 or 33 U.S.C. § 1321(b)(5).

nn. “Response and Action Plan” means the plan developed and implemented by Defendants under Paragraph 67 to correct any Audit Findings.

oo. “Section” means a portion of this Decree identified by a Roman numeral. pp. “Site” means the Blacktail Creek Remediation Site in Marmon, North

Dakota, as generally depicted on the map attached as Appendix C.

qq. “Spill Response Plan” means a plan to minimize the incidence, frequency, duration, and environmental impact of Reportable Discharges from a Pipeline Facility, meeting the requirements of Paragraph 43.

rr. “State” means the State of North Dakota, acting on behalf of NDDEQ and

NDGF.

ss. “Third-Party Auditor” means any independent third party approved pursuant to Section X.H to serve as EMS Consultant, EMS Auditor, or CPM System and Control Room Auditor.

tt. “Third-Party Inspector” means any third-party inspector meeting the requirements of Section X.H and contracted by Defendants to perform the duties set forth in Paragraph 32 or 34.

uu. “Trustees” means DOI, NDDEQ, and NDGF.

vv. “United States” means the United States of America, acting on behalf of

EPA and DOI.

ww. “USDOJ” means the United States Department of Justice.

V.STATEMENT OF PURPOSE

9.In entering into this Decree, the objectives of the Parties are to: (a) provide for payment of an appropriate civil penalty relating to the Blacktail Creek Discharge; (b) prevent Reportable Discharges and otherwise ensure compliance with the Clean Water Act and N.D.C.C. ch. 61-28; (c) provide for the remediation of environmental contamination resulting from the

Blacktail Creek Discharge; (d) ensure the restoration, replacement, or acquisition of the equivalent of the natural resources allegedly injured, destroyed, or lost as a result of the Blacktail Creek Discharge; (e) reimburse Natural Resource Damages assessment costs incurred by the Trustees; (f) resolve Defendants’ liability as provided herein; and (g) avoid potentially costly and time-consuming litigation.

VI.CIVIL PENALTY

10.Defendants shall pay a total civil penalty in the principal amount of $20 million, with Interest. The civil penalty shall be divided as follows: $10,000,000 to the United States,

$7,525,712 to NDDEQ, and $2,474,288 to NDIC.

11.Defendants shall pay the principal penalty amount in the following installments:


Deadline	Payment to the United States	Payment to the State
30 Days after Effective Date	$1,000,000	$833,333
1 Year After Effective Date	$1,000,000	$833,333
2 Years After Effective Date	$2,000,000	$1,666,667
3 Years After Effective Date	$2,000,000	$1,666,667
4 Years After Effective Date	$2,000,000	$1,666,667
5 Years After Effective Date	$2,000,000	$1,666,667
6 Years After Effective Date	--	$1,666,667

Each installment payment shall also include an additional sum for Interest accrued on the unpaid portion of the principal amount compounded on an annual basis from the Effective Date until the date of the payment. The first installment payment, if timely paid, shall include no Interest.

12.The amount due to the State under Paragraph 11 shall be divided equally between NDDEQ and NDIC until the entire $2,474,288 due to NDIC has been paid, with Interest.

13.If Defendants fail to make any payment required by Paragraph 11 by the required due date, all remaining installment payments and all accrued Interest shall become due immediately upon such failure. If the first payment is not timely made, Interest shall accrue from the Effective Date. Interest shall continue to accrue on any unpaid amounts until the total amount due has been received. Interest required by this Paragraph shall be in addition to any stipulated penalties owed pursuant to Paragraph 82.

14.The Financial Litigation Unit (“FLU”) of the U.S. Attorney’s Office for the District of North Dakota shall send a calculation of the Interest due for each payment to Defendants. Defendants may pay any installment payment prior to the due date but must contact the FLU in advance for a determination regarding the amount of Interest to be included with the payment. In the event any installment payment includes an overpayment, the amount of the overpayment shall be applied to the remaining principal.

15.State Supplemental Environmental Projects. In lieu of paying up to a maximum of

$3,762,856 of the penalty due to NDDEQ, Defendants may complete a Supplemental Environmental Project(s) (“SEP”) in accordance with the provisions of this Paragraph.

a.Within 120 days of the Effective Date, Defendants shall submit to NDDEQ a SEP proposal that describes the SEP(s), implementation, and costs. The SEP proposal must conform to NDDEQ’s SEP Policy. NDDEQ will review the SEP proposal, provide comments as necessary and preliminarily approve or disapprove the SEP proposal. In approving the SEP Plan,

NDDEQ will determine how the amount paid for the SEP(s) will be credited against the payments owed in Paragraph 11.

b.Within 120 days of NDDEQ’s preliminary approval of a SEP proposal, Defendants shall submit a detailed SEP Plan that includes a budget, scheduled milestones,

contractors, and a description of the intended public health or environmental benefits. If the SEP involves making a payment to a third party, Defendants shall submit documentation showing that the third party has the ability to properly complete the SEP, and NDDEQ may require written agreements or confirmations from the third party.

c.NDDEQ will review the SEP Plan and provide comments. Defendants shall adjust the SEP Plan in accordance with NDDEQ’s comments and resubmit the updated SEP Plan to NDDEQ within 30 Days of receipt of NDDEQ’s comments. Upon NDDEQ’s approval of the SEP Plan, Defendants shall begin implementation of the SEP by the deadline provided in the NDDEQ-approved SEP Plan.

d.If, within one year of the Effective Date, the Parties are unable to agree on SEP(s) for all or part of the $3,762,856, Defendants must pay the $3,762,856 minus the amount of any NDDEQ-approved SEP(s). Any payment due under this Paragraph shall be paid subject to the provisions applicable to the civil penalty in this Section, except that it shall be added on a pro rata basis to the portion of the remaining installments due to NDDEQ under Paragraph 11.

e.Submissions under this Paragraph are not subject to Paragraph 26.

f.Defendants shall not propose any SEP(s) that are otherwise required by any federal, state or local law or regulation; nor may Defendants propose any SEP(s) required by any other agreement, grant or injunctive relief. Defendants shall certify compliance with this Paragraph at the time of proposing any SEP.

g.Failure to complete a SEP according to a SEP Plan shall be deemed a violation of this Decree and Defendants shall become liable for stipulated penalties as set forth in Section XIII (Stipulated Penalties).

16.United States Payment Instructions.

a.Defendants shall make payment to the United States by FedWire Electronic Funds Transfer (“EFT”) in accordance with instructions provided by the FLU after the Effective Date. The payment instructions provided by the FLU will include a Consolidated Debt Collection System (“CDCS”) number, which Defendants shall use to identify all payments required to be made in accordance with this Consent Decree. The FLU will provide the payment instructions to:

Matt Sicinski

Vice President, Chief Accounting Officer 910 Louisiana Street, Suite 4200

Houston, Texas 77002

(832) 413-4777

matt.sicinski@summitmidstream.com

on behalf of Defendants. Defendants may change the individual to receive payment instructions on its behalf by providing written notice of such change to USDOJ and EPA in accordance with Section XXI (Notices and Submissions).

b.The payment to the United States pursuant to this Section is to be deposited in the Oil Spill Liability Trust Fund.

c.The payment shall reference the Civil Action docket number assigned to this case and DOJ Number 90-5-2-1-11253, and shall specify that the payment is made for CWA civil penalties to be deposited into the Oil Spill Liability Trust Fund pursuant to 33 U.S.C.

§ 1321(s), § 4303 of Pub. L. no. 101-380, and 26 U.S.C. § 9509(b)(8). Any funds received after 11:00 a.m. Eastern Standard Time shall be credited on the next business day.

d.Defendants shall simultaneously provide notice of payment in writing, together with a copy of any transmittal documentation to the EPA and USDOJ, in accordance with Section XXI of this Consent Decree (Notices and Submissions), and to EPA by email to

acctsreceivable.CINWD@epa.gov and to EPA and the Coast Guard at the following addresses:

EPA Cincinnati Finance Office 26 Martin Luther King Drive Cincinnati, Ohio 45268

National Pollution Funds Center United States Coast Guard Stop 7605 2703 Martin Luther King Jr. Ave., SE Washington, D.C. 20593-7605

Such notice shall state that the payment is for the civil penalty owed pursuant to the Consent Decree in United States, et al. v. Summit Midstream Partners, LLC, et al. and shall reference the civil action number, CDCS Number, and DOJ case number 90-5-2-1-11253.

17.Payment to the State. Defendants shall make payment to the State by certified

checks or cashier’s checks as follows:

a.Defendants shall make payments to NDDEQ by certified check or cashier’s check made payable to the “North Dakota Department of Environmental Quality” sent to the attention of L. David Glatt, Director, North Dakota Department of Environmental Quality, 918 E. Divide Ave., Bismarck, ND 58501-1947. To receive proper credit, the check must reference United States, et al. v. Summit Midstream Partners, LLC, et al.

b.Defendants shall make payments to NDIC by certified check or cashier’s check made payable to “North Dakota Industrial Commission, Oil and Gas Division”, attn. Lynn Helms, Director, 1016 East Calgary Ave, Bismarck, ND 58503-5512. Receipt of this payment shall satisfy the penalty for the claims resolved in the Consent Agreement entered between Defendants and the North Dakota Industrial Commission in Case No. 24179.

18.Defendants shall not deduct any penalties or SEP amount paid under this Decree pursuant to this Section or Section XIII (Stipulated Penalties) in calculating its federal or state or local income tax.

VII.CERTIFICATION

19.Defendants certify, to the best of their knowledge and belief, after thorough inquiry, that:

a.they have fully complied with the requests for information identified at

Appendix D;

b.the Financial Information submitted to the United States and the State fairly, accurately, and materially sets forth Defendants’ financial circumstances;

c.Defendants’ financial circumstances have not materially changed between the time the Financial Information was submitted to the United States and the State and the date that Defendants signed this Consent Decree; and

d.Defendants do not have any insurance policies that may cover any payment of a civil or administrative penalty relating to this matter.

VIII.NATURAL RESOURCE DAMAGES

20.Payment for the United States’ Past Assessment and Restoration Planning Costs.

Within 30 Days after the Effective Date, Defendants shall pay a total of $198,000 to the United States for past assessment and restoration planning costs.

21.Payment for the State’s Past Assessment and Restoration Planning Costs. Within

30 Days after the Effective Date, Defendants shall pay a total of $52,000 to NDGF for past assessment and restoration planning costs.

22.Payment for Natural Resource Restoration Projects. Within 30 Days after the

Effective Date, Defendants shall pay a total of $1,000,000 to the United States for joint use by the Trustees. The total amount paid under this Paragraph shall be deposited into a distinct account within the NRDAR Fund for use as set forth in Paragraph 23.

23.Trustees’ Management and Application of Funds. All funds deposited in the

segregated NRDAR Fund account under Paragraph 22 shall be used to pay for the costs and administration of projects that restore, rehabilitate, replace, or acquire the equivalent of natural resources pursuant to the Restoration Plan and any amendments thereto. Decisions regarding any use or expenditure of funds under this Paragraph shall be made by agreement of the Trustees, acting through the Trustee Council. Defendants shall not be entitled to dispute, in any forum or proceeding, any decision relating to use of funds or restoration efforts.

24.Payment Instructions.

a.Payments to NDGF pursuant to Paragraph 21 shall be made as follows: Defendants shall make payment in a certified check or cashier’s check made payable to the “North Dakota Game and Fish Department” sent to the attention of Kim Kary, Administrative Services Division Chief, North Dakota Game and Fish Department, 100 N. Bismarck Expressway, Bismarck, ND 58501-5095. To receive proper credit, the check must reference United States, et al. v. Summit Midstream Partners, LLC, et al.

b.Payment to the United States pursuant to Paragraphs 20 and 22 shall be made in the manner set forth in Paragraph 16.a. At the time of payment, Defendants shall send notice that payment has been made to: (i) U.S. Department of the Interior, NRDAR Program, Attn: Fund Restoration Manager, 1849 C Street NW, Mailstop 4449, Washington, DC 20240, and (ii) the United States Department of Justice, in accordance with Section XXI of this Consent Decree (Notices and Submissions). Such notice shall state that the payment is for assessment costs and/or restoration costs owed pursuant to the Consent Decree in United States, et al. v. Summit Midstream Partners, LLC, et al. and shall reference the civil action number, CDCS Number, and DOJ case number 90-5-2-1-11253.

25.Interest. In the event any payment required by Paragraphs 20, 21, or 22 is not

made when due, Defendants shall pay Interest on the unpaid balance commencing on the payment due date and accruing through the date of full payment. Payments of Interest made under this Paragraph shall be in addition to such other remedies or sanctions available to Plaintiffs by virtue of Defendants’ failure to make timely payments under this Section, including payment of stipulated penalties pursuant to Section XIII (Stipulated Penalties).

IX.GENERAL COMPLIANCE REQUIREMENTS

26.Approval of Submissions.

a.Defendants shall submit any plan, report, or other item that they are required to submit for approval under this Consent Decree to the Lead Agencies, as applicable.

b.The applicable Lead Agencies shall in writing either:

(1)approve the submission;

(2)approve the submission upon specified conditions;

(3)approve part of the submission and disapprove the remainder; or

(4)disapprove the submission.

c.If the submission is approved pursuant to Paragraph 26.b(1), Defendants shall take all actions required by the plan, report, or other document, in accordance with the schedules and requirements of the plan, report, or other document, as approved. If the submission is conditionally approved or approved only in part pursuant to Paragraph 26.b(2) or 26.b(3), Defendants shall, upon written direction from the applicable Lead Agencies, take all actions required by the approved plan, report, or other item that the applicable Lead Agencies determine are technically severable from any disapproved portions, subject to Defendants’ right to dispute only the specified conditions or the disapproved portions, under Section XV (Dispute

Resolution).

d.If the submission is disapproved in whole or in part pursuant to Paragraph 26.b(3) or 26.b(4), Defendants shall, within 45 Days or such other time as the Parties agree to in writing, correct all deficiencies and resubmit the plan, report, or other item, or disapproved portion thereof, for approval, in accordance with the preceding Paragraphs. If the resubmission is approved in whole or in part, Defendants shall proceed in accordance with the preceding Subparagraph. Any stipulated penalties applicable to the original submission, as provided in Section XIII (Stipulated Penalties), shall accrue during the 45-Day period or other specified period, but shall not be payable unless the resubmission is untimely or is disapproved in whole or in part; provided that, if the original submission was so deficient as to constitute a material breach of Defendants’ obligations under this Decree, the stipulated penalties applicable to the original submission shall be due and payable notwithstanding any subsequent resubmission.

e.If a resubmitted plan, report, or other item, or portion thereof, is disapproved in whole or in part, the applicable Lead Agencies may again require Defendants to correct any deficiencies, in accordance with the preceding Paragraphs, subject to Defendants’ right to invoke Dispute Resolution and the right of the United States and the State to seek stipulated penalties.

27.Permits. Where any compliance obligation under this Section requires Defendants

to obtain a federal, state, or local permit or approval, Defendants shall submit timely and complete applications and take all other actions necessary to obtain all such permits or approvals. Defendants may seek relief under the provisions of Section XIV (Force Majeure) for any delay in the performance of any such obligation resulting from a failure to obtain, or a delay in obtaining, any permit or approval required to fulfill such obligation, if Defendants have

submitted timely and complete applications and have taken all other actions necessary to obtain all such permits or approvals.

28.Compliance with Applicable Law. All activities undertaken by Defendants

pursuant to this Decree shall be performed in accordance with the requirements of all applicable federal, state, and local laws and regulations.

29.This Decree is not, and shall not be construed to be, a permit issued pursuant to any federal, state, or local law or regulation.

30.All references in this Consent Decree to ASME and API guidelines and recommended practices shall be interpreted to mean the most recent version of the guideline or recommended practice in effect at the time of implementation of the relevant Consent Decree requirement, unless otherwise indicated.

X.SPECIFIC COMPLIANCE REQUIREMENTS

A.Pipeline Installation, Operation, and Testing

31.Defendants shall comply with N.D.A.C. § 43-02-03-29.1 and all applicable Pipeline manufacturer’s prescribed installation, operation, and maintenance practices at their Pipeline Facilities.

32.Defendants may not commence operation of any Pipeline installed after the Effective Date until obtaining written certification from a Third-Party Inspector that (a) the Pipeline has been inspected and meets the requirements of Paragraph 33, and (b) the Pipeline has been pressure tested and demonstrated integrity pursuant to the requirements of Paragraph 34.

33.Inspection of New Pipelines. All Pipelines installed after the Effective Date must

be inspected by a Third-Party Inspector to ensure the Pipeline is installed as prescribed by the manufacturer’s specifications and in accordance with applicable regulations.

34.Pressure Testing of Pipelines.

a.For Pipelines (i) installed; (ii) repaired; (iii) replaced; (iv) relocated; or (v) altered so that the composition, size, design temperature, or design pressure changes after the Effective Date, Defendants shall complete Pressure Testing prior to commencing operation of that Pipeline or Pipeline segment.

b.All testing shall be witnessed by a Third-Party Inspector.

c.At least ten business days prior to testing, Defendants shall notify EPA, NDDEQ, and NDIC to allow their representatives to witness the testing process and results. Should subsequent events require the test to be rescheduled, Defendants shall notify EPA, NDDEQ, and NDIC of any such schedule changes as soon as they occur, but no later than one business day in advance of the rescheduled test.

d.Defendants shall submit a written report of testing results to EPA, NDDEQ, and NDIC within 60 Days of the Pressure Test, which shall include the following


information:
	(1)	The name of the Pipeline gathering system and any other
		separately named portions thereof;
	(2)	The date of the test;
	(3)	The duration of the test;
	(4)	The length of Pipeline which was tested;
	(5)	The maximum and minimum test pressure and the corresponding
		elevation at those pressures;
	(6)	The starting and ending pressure;
	(7)	A copy of the chart recorder results, including time/pressure logs;

(8)A GIS layer utilizing North American datum 83 geographic coordinate system and in an Environmental Systems Research Institute shape file format showing the location of the centerline of the portion of the Pipeline that was tested; and

(9)A Third-Party Inspector certification that the Pipeline has been pressure tested and demonstrated integrity; or identification of any leaks, ruptures, or other integrity issues, as applicable.

e.In the event of a leak, rupture, or other integrity issue identified during a

Pressure Test:

(1)Defendants shall immediately take all actions necessary to prevent any discharge from reaching or spreading to any body of water.

(2)Within 30 Days of the Pressure Test, Defendants shall submit to EPA, NDDEQ, and NDIC a report that includes a discussion of the failure mechanism based upon investigation of the section of Pipeline involved, a description of corrective action measures taken or planned, and a timeline for completion of corrective action measures.

(3)Operation of the Pipeline may not commence until Defendants have implemented all corrective action measures under Paragraph 34.e(2), as applicable, and have thereafter submitted to EPA, NDDEQ, and NDIC a certificate from the Third-Party Inspector verifying that the Pipeline has been pressure tested and demonstrated integrity.

35.Existing Pipelines.

a.Except as otherwise provided in Paragraphs 35.b-35.c, Defendants shall not exceed Maximum Operating Pressure at their Existing Pipelines. Defendants shall implement the following measures to ensure that MOP is not exceeded:

(1)For all pumps associated with Existing Pipelines, set and maintain pump shutdown level at MOP;

(2)Maintain relief valves on all Existing Pipelines;

(3)Ensure that any changes to the method of controlling or limiting pressure on the system are subject to a Management of Change Procedure, including an engineering evaluation and approval from the Director of Asset Integrity and Compliance; and

(4)Provide annual reporting of pressure data in accordance with Paragraph 72.a(3).

b.Defendants shall not increase MOP and/or relief valve set points for an Existing Pipeline unless they first implement the following measures:

(1)Provide 30 Days’ advance notice to EPA, NDDEQ, and NDIC of the proposed MOP;

(2)Conduct Hydrostatic Testing to at least 125% of the proposed MOP, for at least 4 continuous hours, and an additional 4 hours at a pressure of at least 110% of the proposed MOP if the piping is not visible. Defendants shall follow the testing, notification, and reporting procedures set forth in Paragraphs 34.b-34.d; and

(3)In the event of a leak, rupture, or other integrity issue identified

during the hydrostatic pressure test, comply with the requirements of Paragraph 34.e.

c.Upon compliance with Paragraph 35.b, the proposed MOP shall become the MOP for the applicable Existing Pipeline for purposes of Paragraph 35.a.

B.Control Room and Computational Pipeline Monitoring System

36.Control Room. Defendants shall implement and manage a Control Room that

conforms with API Recommended Practice 1168 (Pipeline Control Room Management) (2008 edition), and shall ensure that the Control Room is staffed sufficiently to: (a) effectively manage operator fatigue, including a maximum 65 hours of service per operator within a sliding 7-day period, and with shifts not greater than 14 hours, and (b) timely respond to alarms from a CPM System that is fully compliant with API Recommended Practice 1130. Alarm response procedures shall be consistent with best practices identified in API Recommended Practice 1167 (Pipeline SCADA Alarm Management) (2007 edition) and shall include remote shutdown of the affected Pipeline Facility if Control Room staff are unable to identify the cause of the alarm within one hour.

37.CPM System. Defendants shall maintain continuous and uninterrupted operation

of a CPM System for all Pipelines throughout the term of this Decree, except in circumstances where a communication issue causes an interruption, in which case the affected LACT unit shall be shut down until communication is restored and the interruption is resolved. The CPM System and its operation shall conform with API Recommended Practice 1130 (Computational Pipeline Monitoring for Liquids), taking into account the procedures identified in API Technical Report 1149 (Pipeline Variable Uncertainties and Their Effects on Leak Detectability). The CPM System shall be designed in accordance with industry standards to preserve data relating to the source of the alarm, the time and date at which it began, and the time when the alarm was

cleared. All data maintained by the CPM System shall be available to EPA, NDDEQ, and NDIC upon request.

38.Control Room and CPM System Audit. Within 30 Days of approval of the CPM

System and Control Room Auditor(s) pursuant to Paragraph 64, the CPM System and Control Room Auditor(s) shall conduct a one-time audit of the Control Room, CPM System, and relevant operational procedures for: (a) compliance with the requirements of Paragraphs 36 and 37, (b) appropriateness of alarm thresholds, (c) appropriateness of prescribed alarm response times, including the time frame for remote shutdown identified in Paragraph 36, (d) effectiveness of fatigue management, and (e) adequacy of resources to timely respond to CPM System alarms.

Defendants may employ multiple auditors to meet the requirements of this Paragraph, subject to the requirements of Section X.H (Requirements for Third-Party Inspectors and Third-Party Auditors).

C.Line Visibility and Inspection

39.Line visibility. Defendants shall mark all produced water Pipelines according to

the requirements otherwise applicable to crude oil lines under 49 C.F.R. § 195.410, but using messages and color schemes appropriate for produced water pipelines. Cultivated fields need only be marked as the Pipeline enters or leaves the field. Defendants shall conduct regular maintenance of any rights of way of Pipelines to ensure surface is visible during inspection.

40.Inspections. Defendants shall conduct visual inspections of the ground surface

and water bodies above and adjacent to all Pipelines to look for any indication that the integrity of the buried components or equipment is compromised, as follows:

a.Defendants shall conduct aerial inspections by helicopter of all Pipelines no fewer than 26 times each calendar year. There shall be no more than 21 Days between each inspection. Pilots conducting such aerial inspections shall be OQ Qualified.

b.Defendants must conduct on-the-ground inspections of all Pipelines no fewer than four times per calendar year, with no less than two months between each inspection. Where the Consent Decree term encompasses a partial calendar year (i.e., the year the Consent Decree becomes effective and the year the Consent Decree is terminated), Defendants shall conduct an on-the-ground inspection at least once every three months, with no less than two months between each inspection, and no less than one inspection per partial year. On-the-ground inspections shall be conducted by OQ Qualified employees, using commercial GPS handheld devices to verify location, date, time, and duration of inspection.

c.Defendants shall maintain written documentation of each inspection, including location, date, time, and duration of each inspection, and photographs of any identified irregularities.

d.If the inspection reveals any Reportable Discharges, Defendants shall immediately shut down the affected portion of Pipeline and provide notification to Defendants’ management, the National Response Center, EPA, NDDEQ, and NDIC.

e.Defendants shall implement timely corrective measures to address all irregularities identified during an inspection.

41.Within 30 Days of the Effective Date, Defendants shall submit for approval by EPA and NDDEQ protocols for aerial and on-the-ground inspections, including identification of line location, maximum distance of inspector from pipeline, conditions to observe, and procedures for reporting and responding to Reportable Discharges and other irregularities.

42.Within 30 Days of the Effective Date, Defendants shall submit for approval by EPA and NDDEQ an internal program to audit the effectiveness of aerial and on-the-ground inspections.

D.Spill Response Planning and Countermeasures

43.Within 9 months after the Effective Date, Defendants shall submit to EPA and NDDEQ Spill Response Plans for all Pipeline Facilities to minimize the incidence, frequency, duration, and environmental impact of Reportable Discharges, along with electronic GIS layers of the maps included in the Spill Response Plans. The Spill Response Plans shall include maps identifying the locations of the Pipeline Facilities, environmentally sensitive areas, and Pipeline control and monitoring points such as valves, pumps, meters, tanks, and disposal well locations.

44.Within twelve months of the Effective Date and once per calendar year thereafter, Defendants shall conduct a tabletop response exercise in North Dakota. Within three years of the Effective Date and every three years thereafter, Defendants shall conduct a full-scale response exercise in North Dakota. The first full-scale response exercise, and every other full-scale exercise thereafter, shall be unannounced to the personnel responsible for implementing the Spill Response Plans and shall be initiated by Defendants. Each full-scale exercise shall test tactical deployment of personnel and equipment for containment/recovery and techniques for responding to overland flow and impacted banks and vegetation. At least 30 Days prior to each full-scale response exercise, Defendants shall notify EPA and NDDEQ to allow their representatives to witness the response exercise.

45.Defendants shall conduct community outreach sessions once a year in western North Dakota. Defendants shall invite local city, county, and tribal officials, emergency responders, and other members of the public that may be impacted by Reportable Discharges from Defendants’ Pipelines to participate in a workshop focused on how to respond in the event of a Reportable Discharge, where to obtain Reportable Discharge information, and how to report Reportable Discharges to regulators.

46.In the event of a Reportable Discharge, Defendants shall:

a.Immediately implement Spill Response Plans and take all other actions necessary to minimize and prevent the spread of the Reportable Discharge, including the immediate shutdown of the affected Pipeline Facility and dispatch of trained personnel to the location of the Reportable Discharge;

b.Prior to restarting the affected Pipeline Facility:

(1)conduct a root cause analysis, including an evaluation of the cause(s) of the Reportable Discharge, recommendations to prevent a similar Reportable Discharge from recurring, and a schedule to implement the recommendations;

(2)implement all recommendations from the root cause analysis, in accordance with the schedule therein; and

(3)conduct third-party integrity testing in compliance with Paragraph 34 and N.D.A.C. § 43-02-03-29.1(13), (14).

47.In the event that a Reportable Discharge is not first identified by the CPM System or Defendants’ visual inspections, Defendants shall conduct an investigation into why the CPM System and/or visual inspections failed to identify the Reportable Discharge, and what improvements to the CPM System and visual inspection procedures should be made to address identified failures. The results of the investigation shall be documented in a Leak Detection Investigation Report, which shall include a schedule for implementation of identified improvements to the CPM System and visual inspection procedures. Defendants shall implement the improvements identified in the Leak Detection Investigation Report according to the schedule therein.

48.The spill response and countermeasures requirements of this Section X.D are in addition to, and not in lieu of, any similar requirements in applicable federal and state statutes and regulations, including those specified in CWA Section 311(j), 42 U.S.C. § 1321(j), and 40

C.F.R. Part 112.

E.Environmental Management System

49.Defendants have developed a company-wide EMS. Defendants shall audit, implement, and maintain the company-wide EMS in accordance with the requirements of this Consent Decree.

50.EMS Criteria. The EMS must: (a) outline a plan for achieving and maintaining

compliance with the CWA, N.D.C.C. ch. 61-28, N.D.A.C. § 43-02-03-29.1, and other applicable environmental regulations; (b) include procedures for inspections, spill prevention, spill reporting, waste handling and disposal, permit issuance, spill sampling, external inspections, contingency planning for directional drilling (if applicable), and implementation of Consent Decree requirements; and (c) include the elements set forth in Appendix B.

51.Initial EMS Review and Evaluation. Within 90 Days of EPA and NDDEQ’s

approval of the EMS Consultant pursuant to Paragraph 64, the EMS Consultant shall review and evaluate Defendants’ current EMS to identify where systems or subsystems have not been adequately developed or implemented, or need to be enhanced, or new management systems or subsystems need to be developed to adequately address the requirements in this Consent Decree and the EMS Criteria.

52.EMS Implementation. Within 6 months of the Initial EMS Review and

Evaluation, Defendants shall implement the EMS Consultant’s recommendations, including any recommended revisions to the EMS Manual, and submit the revised EMS Manual to EPA and NDDEQ for review. The EMS Manual shall describe or contain, as appropriate, overarching

policies, procedures, and programs that compose the Pipeline Facility-wide EMS framework, and respective management systems, subsystems, and tasks for the EMS Criteria. The EMS Manual shall also contain an implementation schedule for each of the described systems and subsystems not already fully implemented.

a.Upon completion of the EMS Manual, Defendants shall commence implementation of the EMS in accordance with the schedule contained in the EMS Manual.

b.Defendants may revise and/or update the EMS Manual for the Pipeline Facilities. Material revisions or updates to the EMS Manual made by Defendants shall be submitted to EPA and NDDEQ for review.

c.EPA and NDDEQ may require that Defendants obtain certification from the EMS Consultant that the EMS Manual or any material revisions or updates thereto are consistent with the requirements of this Paragraph.

53.EMS Audit. Within 12 months after implementation of the EMS Consultant’s

recommendations pursuant to Paragraph 52, the EMS Auditor shall perform an audit of Defendants’ EMS. The EMS Audit shall evaluate the adequacy of EMS implementation relative to the EMS Manual and the EMS Criteria, and identify areas of concern, from top management down, throughout each major organizational unit with responsibilities under the EMS Manual. The EMS Audit shall be conducted in accordance with ISO 19011, and shall determine the following:

a.Whether there is a defined system, subsystem, program, or planned task for the respective EMS element.

b.To what extent the system, subsystem, program, or task has been implemented, and is being maintained.

c.The adequacy of each operation’s internal self-assessment procedures for programs and tasks composing the EMS.

d.The adequacy of pollution prevention and environmental training, including current practices and procedures to track training and the availability of and access to training resources.

e.The adequacy of reference materials related to each environmental procedure required by this Consent Decree or the EMS.

f.The adequacy of reporting methods to report environmental concerns to Defendants’ management and to appropriate state and federal authorities.

g.Whether Defendants are effectively communicating environmental requirements, including the requirements of the Consent Decree, to affected parts of the organization, or those working on behalf of the organization.

h.Whether further improvements should be made to the EMS to better conform to the audit criteria.

i.Whether there are observed deviations from Defendants’ written requirements or procedures.

j.Whether continual improvement is occurring.

54.EPA and NDDEQ may participate in the EMS Audit as observers. Defendants shall notify EPA and NDDEQ at least 14 Days before the commencement of the on-site portion of the EMS Audit.

F.Data Management

55.Defendants shall create and maintain a centralized electronic database to track information relevant to: (a) training of employees and contractors, and (b) Pipeline Facility condition and operation, in order to assist in identifying potential risks of failures and to schedule

and track inspection, audit, maintenance, repair, and replacement requirements.

56.The database shall include for each Pipeline Facility:

a.Description of Pipeline Facility, including manufacturer and material;

b.Manufacturer’s prescribed installation, operation, and maintenance

guidelines;

c.Dates of installation, start of operation, and any period the Pipeline Facility is taken out of operation;

d.Pipeline Facility repairs and replacement;

e.Visual inspection results;

f.Pressure Test results;

g.Relevant Audit Findings;

h.Reportable Discharges, including root cause analysis; and

i.Where corrective measures are identified in any Response and Action Plan or otherwise identified as a result of inspections, tests, audits, or root cause analyses, information on the planned measures, responsible employees, suggested time frame, and completion date.

57.Defendants shall provide access to the database to EPA, NDDEQ, and NDIC upon request. In addition, Defendants shall produce any requested information from the database to EPA, NDDEQ, and NDIC within ten Days of the request.

G.Training

58.Defendants shall conduct annual training of employees and contractors with responsibilities under this Consent Decree and/or the EMS Manual on: visual inspection, Control Room operation, leak detection, EMS, Spill Response Plans, Consent Decree requirements, and spill response and notification procedures.

59.Training must be documented electronically in the centralized electronic database

maintained pursuant to Paragraph 55, with documentation available to EPA, NDDEQ, and NDIC upon request.

H.Requirements for Third-Party Inspectors and Third-Party Auditors

60.Defendants shall pay all costs of and cooperate fully with Third-Party Inspectors and Third-Party Auditors and provide Third-Party Inspectors and Third-Party Auditors access to all records, Pipeline Facilities, and personnel pertinent to their inspection, testing, and auditing requirements.

61.Entities serving as Third-Party Inspectors or Third-Party Auditors shall function independently of Defendants and shall exercise independent judgment to ensure that the objectives of the inspection, testing, or audit are met. Third-Party Inspectors and Third-Party Auditors shall not receive or request approval of any form from any employee, agent, or contractor of Defendants regarding the development, clearance, or evaluation of any document, report, or communication of any kind, whether draft or final, required by this Consent Decree.

62.Third-Party Inspectors and Third-Party Auditors may not participate in the implementation of any actions they recommend, or have: (a) any financial stake in the outcome of the inspection, testing, or audit conducted under the terms of this Decree, (b) ownership interest in Defendants or in any Pipeline Facility, or (c) any ongoing contractual or financial relationship with Defendants or any entity related to Defendants unless expressly disclosed to and approved by EPA, NDDEQ, and NDIC. Defendants shall notify EPA, NDDEQ, and NDIC if any contractual relationships or proposed contractual relationships between Defendants or any entity related to Defendants and the Third-Party Inspectors or Third-Party Auditors arise during the term of the Consent Decree.

63.Qualifications. The Third-Party Inspectors and Third-Party Auditors must have

adequate staff to perform the relevant requirements. The knowledge, skills, and abilities of the

Third-Party Inspectors, Third-Party Auditors, and their staff must align with the criteria of the required inspections and audits. In addition, the following criteria shall apply:

a.Third-Party Inspectors. All Third-Party Inspectors must be qualified to evaluate the phase of construction or testing that is taking place and be knowledgeable on the manufacturer and industry standard requirements for the pipe being installed and tested. A list of all Third-Party Inspectors and a description of each inspector’s qualifications, certifications, experience, and specific training must be provided to EPA, NDDEQ, and NDIC upon request.

b.EMS Consultant and EMS Auditor. The EMS Consultant and EMS Auditor shall each meet the EMS auditor qualification requirements in ISO 14001; have experience in developing and implementing an EMS; have working process knowledge of produced water gathering systems; and have expertise and competence in the applicable regulatory programs under federal and state environmental laws. The EMS Consultant and the EMS Auditor must not have been involved in developing or implementing Defendants’ EMS prior to entry of this Consent Decree. The EMS Auditor must not have served as the EMS Consultant under this Consent Decree.

c.CPM System and Control Room Auditor(s). The CPM System and Control Room Auditor(s) shall have: (i) experience in performing audits for pipeline systems, and (ii) experience in developing and implementing computational pipeline monitoring systems and Control Room procedures, or, if multiple auditors are selected to meet the requirements of Paragraph 38, experience in developing and implementing that aspect of the computational pipeline monitoring system or Control Room procedure for which they are performing the audit. The CPM System and Control Room Auditor(s) must not have been involved in developing or implementing the Control Room or the CPM System, or any associated procedures prior to entry

of the Consent Decree.

64.Selection of Third-Party Auditors. Within 30 Days of the Effective Date,

Defendants shall submit to EPA and NDDEQ for approval a list of at least three qualified candidates each for EMS Consultant, EMS Auditor, and CPM System and Control Room Auditor. If Defendants choose to conduct multiple audits to comply with Paragraph 38 (Control Room and CPM System Audit), the list must include three qualified candidates for each proposed audit. The list shall include: (i) name, affiliation, and address of the proposed Third- Party Auditors, (ii) information demonstrating how each proposed Third-Party Auditor satisfies the applicable requirements in Paragraphs 61, 62 and 63, and (iii) any current or previous work, contractual, or financial relationships with Defendants or any entity related to Defendants. In the event that none of the candidates for a position are found acceptable, or if the work of a Third- Party Auditor is unsatisfactory at any time, EPA and NDDEQ may request that Defendants provide additional candidates. EPA and NDDEQ reserve the right to reject any proposed Third- Party Auditor.

65.Audit Reports. Within 30 Days of each audit identified in Paragraphs 38 (CPM

System Audit), 51 (Initial EMS Review and Evaluation), and 53 (EMS Audit), the Third-Party Auditor shall provide an audit report in an electronically-searchable format to Defendants, EPA, NDDEQ, and NDIC. Each report shall include:

a.A summary of the audit process, including the date(s) the on-site portion of the audit was conducted, identification of the audit team members, and identification of the company representatives and regulatory personnel observing the audit;

b.A summary of the audit scope, including the time period covered by the

audit;

c.A summary of observations, including any obstacles encountered during

the audit;

d.Detailed Audit Findings, including the basis for each finding identified;

e.Identification of any Audit Findings addressed during the audit and recommendations for further corrective measures to address Audit Findings; and

f.Certification by the lead auditor that the audit was conducted in accordance with the provisions of this Decree.

66.In addition to the requirements of Paragraph 65, Third-Party Inspectors and Third-Party Auditors must immediately inform EPA, NDDEQ, and NDIC of any significant discrepancies identified during the inspections or audits.

67.Response and Action Plan. Within 60 Days of receipt of an audit report under

Paragraph 65, Defendants shall develop a Response and Action Plan responding to the Audit Findings, including the result of any root cause analysis, specific deliverables, responsibility assignments, and an implementation schedule of the identified actions and measures. Defendants shall implement the Response and Action Plan in accordance with the schedule identified therein.

XI.REMEDIATION MEASURES

68.Defendants shall perform remediation and monitoring of environmental impacts resulting from the Blacktail Creek Discharge as specified in this Section.

69.Remediation Work Plan. Defendants shall continue to implement the approved

2019 Remediation Work Plan. By December 31, 2021, Defendants shall submit an updated Remediation Work Plan to NDDEQ for review and approval.

a.The update must describe plans for the following activities:

(1)Groundwater remediation,

(2)Surface water remediation,

(3)Site reclamation and restoration,

(4)Monitoring, sampling, and analysis for groundwater, surface water, and soils.

b.All remediation work, including monitoring, sampling, and analysis, must be completed according to the Remediation Work Plan approved by NDDEQ.

70.Remediation Standard. The chloride concentration of groundwater and surface

water at the Site should not exceed 250 mg/L. Defendants shall demonstrate compliance with this standard by showing monitoring results, obtained according to the Sampling and Analysis Plan, which is included in the Remediation Work Plan.

71.Certification of Remediation Completion. The remediation is complete when the

Remediation Work Plan has been fully implemented, the Remediation Standard has been achieved, and the Discharge site has been remediated to a condition that Defendants demonstrate to NDDEQ is supportive of existing and historical receptors and uses. Upon completion of the remediation, Defendants may submit a report requesting NDDEQ’s Certification of Remediation Completion. The report shall include all data, including monitoring, sampling, and analysis data, sufficient to show that the remediation is complete.

a.If NDDEQ concludes the remediation is not complete, NDDEQ shall notify Defendants. NDDEQ’s notice must include a description of any deficiencies. NDDEQ’s notice may include a schedule for addressing such deficiencies or may require Defendants to submit a schedule for NDDEQ’s approval. Defendants shall perform all activities described in the notice in accordance with the schedule.

b.If NDDEQ concludes, based on the initial or any subsequent report requesting Certification of Remediation Completion, that the remediation is complete, NDDEQ shall so certify to Defendants.

XII.REPORTING REQUIREMENTS

72.Defendants shall submit the following reports to Plaintiffs:

a.Annual Reports. Defendants shall submit an annual report by January 30th

of each year to USDOJ, EPA, NDDEQ, and NDIC that shall include the following information as it pertains to the preceding calendar year:

(1)description of any repair or replacement activity on a Pipeline, including notifications and information required by N.D.A.C.

§ 43-02-03-29.1(14), once available;

(2)documentation of any new Pipeline construction, including notifications required by N.D.A.C. § 43-02-03-29.1(3) and information required by N.D.A.C. § 43-02-03-29.1(8), once available;

(3)certification that Defendants did not exceed MOP at Existing Pipelines, and pressure data for Existing Pipelines for the prior year, recorded in one minute increments and provided in spreadsheet format. If MOP for an Existing Pipeline was exceeded during the reporting period, Defendants shall provide an identification of the amount and duration of exceedance, an explanation of the cause of the exceedance, a description of corrective actions taken or to be taken, and the date(s) for

completion of the corrective actions;

(4)summary reports of CPM System data, including alarms or notifications that relate to Reportable Discharges and associated corrective action, and data discrepancies identified pursuant to N.D.A.C. § 43-02-03-29.1(10);

(5)information regarding any full-scale response exercise or other planned response exercise completed during the calendar year or scheduled for the next 12 months;

(6)revisions to Spill Response Plans, the EMS, or associated Standard Operating Procedures;

(7)identification of Control Room operators, their qualifications, and training (if changed from previous report); and

(8)after completion of the EMS Manual pursuant to Paragraph 52, certification of compliance with the EMS Manual, or, for any noncompliance, an explanation of the cause of the noncompliance and remedial steps taken or to be taken and a date for achieving compliance.

b.Quarterly Reports. Defendants shall submit quarterly reports at the end of

the month following the end of each calendar-year quarter (i.e., by April 30, July 31, October 31, and January 31) to USDOJ, EPA, NDDEQ, and NDIC that shall include the following information as it pertains to the preceding calendar-year quarter:

(1)Third-Party Inspector certifications pursuant to Paragraph 32;

(2)Third-Party Inspector reports for any Pressure Testing conducted;

(3)documentation of visual inspections required under Paragraph 40.c, including photos of irregularities;

(4)summary of instances in which any corrective measure was not completed by the deadline assigned in the database under Paragraph 56.i, including reasons for delay and estimated completion date for the corrective measure;

(5)identification of any Reportable Discharges, including date, duration, content, volume spilled, whether the discharge reached a surface water, manner in which the spill was identified (e.g., line balancing, visual inspection, report from third party, etc.), response activities, root cause analysis, Leak Detection Investigation Report (as applicable), and steps taken to prevent similar incidents in future;

(6)documentation of remediation activities conducted during the last quarter, and a summary of activities for the following quarter;

(7)all environmental monitoring data collected in connection with remediation activities; and

(8)The status of implementation of any other Consent Decree requirements under Section X (Specific Compliance Requirements) and Section XI (Remediation Measures), and problems encountered or anticipated, together with implemented or proposed solutions.

73.The Lead Agencies for each report identified in Paragraph 72 may reduce the

frequency of the applicable report as appropriate, upon notification to Defendants in writing.

74.Notification of Consent Decree Violation. If Defendants violate, or have reason to

believe that they may violate, any requirement of this Consent Decree, Defendants shall notify Plaintiffs of such violation and its likely duration, in writing, within ten business days of the Day Defendants first become aware of the violation, with an explanation of the violation’s likely cause and of the remedial steps taken, or to be taken, to prevent or minimize such violation. If the cause of a violation cannot be fully explained at the time the written notice is due, Defendants shall so state in the written notice. Defendants shall investigate the cause of the violation and shall then submit an amendment to the written notice, including a full explanation of the cause of the violation, within 30 Days of the Day Defendants become aware of the cause of the violation. Nothing in this Paragraph or the following Paragraph relieves Defendants of their obligation to provide the notice required by Section XIV (Force Majeure).

75.Whenever any violation of this Consent Decree or any applicable permits or any other event affecting Defendants’ performance under this Decree, or the performance of the Pipeline Facilities, may pose an immediate threat to the public health or welfare or the environment, Defendants shall notify EPA, NDDEQ, and NDIC orally or by email as soon as possible, but no later than 24 hours after Defendants first knew of the violation or event. This procedure is in addition to the requirements set forth in Paragraph 74.

76.All written reports or submissions required of Defendants under this Consent Decree shall be signed by an official of the Defendants and include the following certification:

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I have no personal knowledge that the information

submitted is other than true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

77.This certification requirement does not apply to emergency or similar notifications where compliance would be impractical.

78.Public Website. Defendants shall make the following information available on a

public website, posted on a quarterly basis:

a.identification of any Reportable Discharge, including date, duration, content, volume spilled, and response activities;

b.summary description of any replacement of a line segment on a Pipeline, or any material repair following a Reportable Discharge; and

c.summary of environmental monitoring data collected in connection with remediation activities for the Reportable Discharge.

79.The reporting requirements of this Consent Decree do not relieve Defendants of any reporting obligations required by the CWA or implementing regulations, N.D.C.C. ch. 61-28 or implementing regulations, or any other federal, state, or local law, regulation, permit, or other requirement.

80.Any information provided pursuant to this Consent Decree may be used by the United States and the State in any proceeding to enforce the provisions of this Consent Decree and as otherwise permitted by law.

XIII.STIPULATED PENALTIES

81.Defendants shall be liable for stipulated penalties to the United States and the State for violations of this Consent Decree as specified below, unless excused under Section XIV (Force Majeure). A violation includes failing to perform any obligation required by the terms of

this Decree, including any work plan or schedule approved under this Decree, according to all applicable requirements of this Decree and within the specified time schedules established by or approved under this Decree.

82.Late Payment. If Defendants fail to make any payment required under Paragraphs

10-13 (civil penalty and interest) and Section VIII (Natural Resource Damages) when due, Defendants shall pay a stipulated penalty of $7,500 per Day for each Day that the payment is late.

83.Noncompliance with Reporting Requirements. The following stipulated penalties

shall accrue per violation per Day for each violation of the reporting requirements of Section XII:

Penalty Per Violation Per Day Period of Noncompliance

$500. 1st through 14th day

$1,000 15th through 30th day

$2,000 31st day and beyond

84.Noncompliance with Consent Decree. The following stipulated penalties shall

accrue per violation per Day for each violation of any requirement of this Consent Decree, other than payments under Paragraphs 10-13 (civil penalty and interest), Section VIII (Natural Resource Damages), and Section XII (Reporting Requirements):

Penalty Per Violation Per Day Period of Noncompliance

$2,000 1st through 14th day

$3,500 15th through 30th day

$5,000 31st day and beyond

85.Stipulated penalties under this Section shall begin to accrue on the Day after performance is due or on the Day a violation occurs, whichever is applicable, and shall continue to accrue until performance is satisfactorily completed or until the violation ceases. Stipulated

penalties shall accrue simultaneously for separate violations of this Consent Decree.

86.Defendants shall pay stipulated penalties to the United States and the State within 30 Days of a written demand by either Plaintiff. For violations of requirements in Section XI (Remediation Measurements), Defendants shall pay 100 percent of the total stipulated penalty amount due to the State. For all other violations, Defendants shall pay 50 percent of the total stipulated penalty amount due to the United States and 50 percent to the State. The Plaintiff making a demand for payment of a stipulated penalty shall simultaneously send a copy of the demand to the other Plaintiff.

87.Either Plaintiff may in the unreviewable exercise of its discretion, reduce or waive stipulated penalties otherwise due it under this Consent Decree.

88.Stipulated penalties shall continue to accrue as provided in Paragraph 85 during any Dispute Resolution, but need not be paid until the following:

a.If the dispute is resolved by agreement of the Parties or by a decision of the United States and the State that is not appealed to the Court, Defendants shall pay accrued penalties determined to be owing, together with Interest, to the United States and the State within 30 Days of the effective date of the agreement or the receipt of the United States’ and the State’s decision or order.

b.If the dispute is appealed to the Court and the United States or the State prevails in whole or in part, Defendants shall pay all accrued penalties determined by the Court to be owing, together with Interest, within 60 Days of receiving the Court’s decision or order, except as provided in subparagraph c, below.

c.If any Party appeals the District Court’s decision, Defendants shall pay all accrued penalties determined to be owing, together with Interest, within 15 Days of receiving the

final appellate court decision.

89.Defendants shall pay stipulated penalties owing to the United States in the manner set forth in Paragraph 16.a. At the time of payment, Defendants shall send notice that payment has been made to EPA, DOI, and USDOJ, in accordance with Section XXI of this Consent Decree (Notices and Submissions). Such notice shall state that the payment is for stipulated penalties owed pursuant to the Consent Decree in United States, et al. v. Summit Midstream Partners, LLC, et al., shall state for which violation(s) the penalties are being paid, and shall reference the civil action number, CDCS Number, and DOJ case number 90-5-2-1-11253.

90.Defendants shall pay stipulated penalties owing to the State in the manner required by Paragraph 17.a, except that the check shall be accompanied by a transmittal letter stating that the payment is for stipulated penalties and shall state for which violation(s) the penalties are being paid.

91.If Defendants fail to pay stipulated penalties according to the terms of this Consent Decree, Defendants shall be liable for Interest on such penalties accruing as of the date payment became due. Nothing in this Paragraph shall be construed to limit the United States or the State from seeking any remedy otherwise provided by law for Defendants’ failure to pay any stipulated penalties.

92.The payment of penalties and Interest, if any, shall not alter in any way Defendants’ obligation to complete the performance of the requirements of this Consent Decree.

93.Non-Exclusivity of Remedy. Stipulated penalties are not Plaintiffs’ exclusive

remedy for violations of this Consent Decree. Subject to the provisions of Section XVII (Effect of Settlement) and Section XVIII (Reservation of Rights by the Plaintiffs), each Plaintiff expressly reserves the right to seek any other relief it deems appropriate for Defendants’

violation of this Decree or applicable law, including but not limited to an action against Defendants for statutory penalties, additional injunctive relief, mitigation or offset measures, and/or contempt. However, the amount of any statutory penalty assessed for a violation of this Consent Decree shall be reduced by an amount equal to the amount of any stipulated penalty assessed and paid pursuant to this Consent Decree.

XIV.FORCE MAJEURE

94.“Force majeure,” for purposes of this Consent Decree, is defined as any event arising from causes beyond the control of Defendants, of any entity controlled by Defendants, or of Defendants’ contractors, that delays or prevents the performance of any obligation under this Consent Decree despite Defendants’ best efforts to fulfill the obligation. The requirement that Defendants exercise “best efforts to fulfill the obligation” includes using best efforts to anticipate any potential force majeure event and best efforts to address the effects of any potential force majeure event (a) as it is occurring and (b) following the potential force majeure, such that the delay and any adverse effects of the delay are minimized. “Force Majeure” does not include Defendants’ financial inability to perform any obligation under this Consent Decree or unanticipated or increased costs or expenses associated with the performance of Defendants’ obligations under this Consent Decree.

95.If any event occurs or has occurred that may delay the performance of any obligation under this Consent Decree, whether or not caused by a force majeure event, Defendants shall provide notice orally or by email to the applicable Lead Agencies, as soon as practicable, but in no event later than 72 hours of when Defendants first knew that the event might cause a delay. Within seven Days thereafter, Defendants shall provide in writing to the applicable Lead Agencies an explanation and description of the reasons for the delay; the

anticipated duration of the delay; all actions taken or to be taken to prevent or minimize the delay; a schedule for implementation of any measures to be taken to prevent or mitigate the delay or the effect of the delay; Defendants’ rationale for attributing such delay to a force majeure event if they intend to assert such a claim; and a statement as to whether, in the opinion of Defendants, such event may cause or contribute to an endangerment to public health, welfare or the environment. Defendants shall include with any notice all available documentation supporting the claim that the delay was attributable to a force majeure. Failure to comply with the above requirements shall preclude Defendants from asserting any claim of force majeure for that event for the period of time of such failure to comply, and for any additional delay caused by such failure. Defendants shall be deemed to know of any circumstance of which any Defendant, any entity controlled by Defendants, or Defendants’ contractors knew or should have known.

96.If the applicable Lead Agencies agree that the delay or anticipated delay is attributable to a force majeure event, the time for performance of the obligations under this Consent Decree that are affected by the force majeure event will be extended by the Lead Agencies for such time as is necessary to complete those obligations. An extension of the time for performance of the obligations affected by the force majeure event shall not, of itself, extend the time for performance of any other obligation. The Lead Agencies will notify Defendants in writing of the length of the extension, if any, for performance of the obligations affected by the force majeure event.

97.If the applicable Lead Agencies do not agree that the delay or anticipated delay has been or will be caused by a force majeure event, the Lead Agencies will notify Defendants in writing of their decision.

98.If Defendants elect to invoke the dispute resolution procedures set forth in

Section XV (Dispute Resolution), they shall do so no later than 15 Days after receipt of notice pursuant to Paragraph 97. In any such proceeding, Defendants shall have the burden of demonstrating by a preponderance of the evidence that the delay or anticipated delay has been or will be caused by a force majeure event, that the duration of the delay or the extension sought was or will be warranted under the circumstances, that best efforts were exercised to avoid and mitigate the effects of the delay, and that Defendants complied with the requirements of Paragraphs 94 and 95. If Defendants carry this burden, the delay at issue shall be deemed not to be a violation by Defendants of the affected obligation of this Consent Decree.

XV.DISPUTE RESOLUTION

99.Unless otherwise expressly provided for in this Consent Decree, the dispute resolution procedures of this Section shall be the exclusive mechanism to resolve disputes arising under or with respect to this Consent Decree. Defendants’ failure to seek resolution of a dispute under this Section shall preclude Defendants from raising any such issue as a defense to an action by the United States or the State to enforce any obligation of Defendants arising under this Decree.

100.Informal Dispute Resolution. Any dispute subject to Dispute Resolution under

this Consent Decree shall first be the subject of informal negotiations. The dispute shall be considered to have arisen when Defendants send DOJ, EPA, and the State a written Notice of Dispute. Such Notice of Dispute shall state clearly the matter in dispute and Defendants’ position. The period of informal negotiations shall not exceed 45 Days from the date the dispute arises, unless that period is modified by written agreement by all Parties. If the Parties cannot resolve a dispute by informal negotiations, then the position advanced by the United States and the State shall be considered binding unless, within 45 Days after the conclusion of the informal

negotiation period, Defendants invoke formal dispute resolution procedures as set forth below.

101.Formal Dispute Resolution. Defendants shall invoke formal dispute resolution

procedures, within the time period provided in the preceding Paragraph, by sending DOJ, EPA, and the State a written Statement of Position regarding the matter in dispute. The Statement of Position shall include, but need not be limited to, any factual data, analysis, or opinion supporting Defendants’ position and any supporting documentation relied upon by Defendants.

102.The United States and the State will send their Statement of Position within 60 Days of receipt of Defendants’ Statement of Position. The United States and the State’s Statement of Position shall include, but need not be limited to, any factual data, analysis, or opinion supporting that position and any supporting documentation relied upon by the United States and the State. The United States and the State’s Statement of Position is binding on Defendants, unless Defendants file a motion for judicial review of the dispute in accordance with the following Paragraph.

103.Defendants may seek judicial review of the dispute by filing with the Court and serving on the United States and the State, in accordance with Section XXI (Notices and Submissions), a motion requesting judicial resolution of the dispute. The motion must be filed within ten Days of receipt of the United States and the State’s Statement of Position pursuant to the preceding Paragraph. The motion shall contain a written statement of Defendants’ position on the matter in dispute, including any supporting factual data, analysis, opinion, or documentation, and shall set forth the relief requested and any schedule within which the dispute must be resolved for orderly implementation of the Consent Decree.

104.The United States and the State shall respond to Defendants’ motion within the time period allowed by the Local Rules of this Court. Defendants may file a reply memorandum,

to the extent permitted by the Local Rules.

105.Standard of Review

a.Disputes Concerning Matters Accorded Record Review. Except as

otherwise provided in this Consent Decree, in any dispute brought under Paragraph 101 pertaining to the adequacy or appropriateness of plans, procedures to implement plans, schedules or any other items requiring approval under this Consent Decree, the adequacy of the performance of work undertaken pursuant to this Consent Decree, and all other disputes that are accorded review on the administrative record under applicable principles of administrative law, Defendants shall have the burden of demonstrating, based on the administrative record, that the position of the United States and the State is arbitrary and capricious or otherwise not in accordance with law.

b.Other Disputes. Except as otherwise provided in this Consent Decree, in

any other dispute brought under Paragraph 101, Defendants shall bear the burden of demonstrating that their position complies with this Consent Decree and better furthers the objectives of the Decree.

106.The invocation of dispute resolution procedures under this Section shall not, by itself, extend, postpone, or affect in any way any obligation of Defendants under this Consent Decree, unless and until final resolution of the dispute so provides. Stipulated penalties with respect to the disputed matter shall continue to accrue from the first Day of noncompliance, but payment shall be stayed pending resolution of the dispute as provided in Paragraph 88. If Defendants do not prevail on the disputed issue, stipulated penalties shall be assessed and paid as provided in Section XIII (Stipulated Penalties).

XVI.INFORMATION COLLECTION AND RETENTION; ACCESS TO PROPERTIES

107.The United States, the State, and their representatives, including attorneys, contractors, and consultants, shall have the right of entry at all reasonable times into any Pipeline Facility or Control Room covered by this Consent Decree, and to the extent that Defendants have such right of entry, any property subject to remediation requirements, in order to:

a.monitor the progress of activities required under this Consent Decree;

b.verify any data or information submitted to the United States or the State in accordance with the terms of this Consent Decree;

c.obtain samples and, upon request, splits of any samples taken by Defendants or their representatives, contractors, or consultants;

d.obtain documentary evidence, including photographs and similar data; and

e.assess Defendants’ compliance with this Consent Decree.

108.Upon request, Defendants shall provide EPA, DOI, and the State or their authorized representatives splits of any samples taken by Defendants. Upon request, EPA, DOI, and the State shall provide Defendants splits of any samples taken by EPA, DOI, or the State.

109.Until three years after the termination of this Consent Decree, Defendants shall retain, and shall instruct their contractors and agents to preserve, all non-identical copies of all documents, records, or other information (including documents, records, or other information in electronic form) in their or their contractors’ or agents’ possession or control, or that come into their or their contractors’ or agents’ possession or control, and that relate in any manner to Defendants’ performance of their obligations under this Consent Decree. This information- retention requirement shall apply regardless of any contrary corporate or institutional policies or procedures. At any time during this information-retention period, upon request by the United

States or the State, Defendants shall provide copies of any documents, records, or other information required to be maintained under this Paragraph.

110.At the conclusion of the information-retention period provided in Paragraph 109, Defendants shall notify the United States and the State at least 90 Days prior to the destruction of any documents, records, or other information subject to the requirements of the preceding Paragraph and, upon request by the United States or the State, Defendants shall deliver any such documents, records, or other information to the United States or the State. Defendants may assert that certain documents, records, or other information is privileged under the attorney-client privilege or any other privilege recognized by federal law. If Defendants assert such a privilege, they shall provide the following: (a) the title of the document, record, or information; (b) the date of the document, record, or information; (c) the name and title of each author of the document, record, or information; (d) the name and title of each addressee and recipient; (e) a description of the subject of the document, record, or information; and (f) the privilege asserted by Defendants. However, no documents, records, or other information created or generated pursuant to the requirements of this Consent Decree shall be withheld on grounds of privilege.

111.Defendants may also assert that information required to be provided under this Section is protected as Confidential Business Information (“CBI”) under 40 C.F.R. Part 2. As to any information that Defendants seek to protect as CBI, Defendants shall follow the procedures set forth in 40 C.F.R. Part 2.

112.This Consent Decree in no way limits or affects any right of entry and inspection, or any right to obtain information, held by the United States or the State pursuant to applicable federal or state laws, regulations, or permits, nor does it limit or affect any duty or obligation of Defendants to maintain documents, records, or other information imposed by applicable federal

or state laws, regulations, or permits.

XVII.EFFECT OF SETTLEMENT

113.Except as specifically provided in Section XVIII (Reservation of Rights by the Plaintiffs), this Consent Decree resolves the civil claims of the United States and the State against the Defendants for injunctive relief under CWA Section 309(b), 33 U.S.C. § 1319(b), and

N.D.C.C. § 61-28-08(5) and civil penalties under CWA Section 311(b), 33 U.S.C. § 1321(b), and

N.D.C.C. § 61-28-08(4), for the violations alleged in the Complaint filed in this action through the date of lodging. The resolution of claims set forth in this Paragraph is conditioned upon the veracity and completeness of the Financial Information provided by Defendants and the Certification made by Defendants in Section VII (Certification).

114.Except as specifically provided in Section XVIII (Reservation of Rights by the Plaintiffs), this Consent Decree resolves the State’s claims for remediation of the known environmental impacts resulting from the Blacktail Creek Discharge. Nothing in this Consent Decree shall preclude the State from seeking, including bringing a new action, Defendants’ investigation, remediation, and monitoring of conditions relating to the Blacktail Creek Discharge that were not known by the State at the time of the lodging of this Decree. For purposes of this Paragraph, conditions known to the State as of the lodging of this Decree shall include only the conditions set forth in the NDDEQ’s files as of the date of the lodging of this Decree.

115.Except as specifically provided in Section XVIII (Reservation of Rights by the Plaintiffs), the United States and the State covenant not to sue or take administrative action against Defendants for Natural Resource Damages resulting from the Blacktail Creek Discharge known as of the date of the lodging of this Consent Decree. This covenant not to sue shall take

effect upon the complete payment of funds required by Section VIII (Natural Resource Damages). This covenant not to sue extends only to Defendants and does not extend to any other person.

116.In any subsequent administrative or judicial proceeding initiated by the United States or the State for injunctive relief, civil penalties, or other appropriate relief relating to the Pipeline Facilities or Defendants’ violations, Defendants shall not assert, and may not maintain, any defense or claim based upon the principles of waiver, res judicata, collateral estoppel, issue preclusion, claim preclusion, claim-splitting, or other defenses based upon any contention that the claims raised by the United States or the State in the subsequent proceeding were or should have been brought in the instant case, except with respect to claims that have been specifically resolved pursuant to Paragraphs 113, 114, and 115.

117.This Consent Decree is not a permit, or a modification of any permit, under federal, state, or local laws or regulations. Defendants are responsible for achieving and maintaining complete compliance with all applicable federal, state, and local laws, regulations, and permits; and Defendants’ compliance with this Consent Decree shall be no defense to any action commenced pursuant to any such laws, regulations, or permits, except as set forth herein. The United States and the State do not, by their consent to the entry of this Consent Decree, warrant or aver in any manner that Defendants’ compliance with any aspect of this Consent Decree will result in compliance with provisions of the CWA, 33 U.S.C. §§ 1311(a), 1321(b), 1321(f)(4), N.D.C.C. ch. 61-28, N.D.C.C. ch. 38-08, N.D.A.C. ch. 43-02-03, and N.D.A.C.

ch. 43-02-05, et seq., or with any other provisions of federal, state, or local laws, regulations, or permits.

118.This Consent Decree does not limit or affect the rights of Defendants or of the

United States or the State against any third parties not party to this Consent Decree, nor does it limit the rights of third parties, not party to this Consent Decree, against Defendants, except as otherwise provided by law.

119.This Consent Decree shall not be construed to create rights in, or grant any cause of action to, any third party not party to this Consent Decree.

XVIII.RESERVATION OF RIGHTS BY THE PLAINTIFFS

120.General Reservations. The United States and the State reserve, and this Decree is

without prejudice to, all rights against Defendants with respect to all matters not expressly included within Paragraphs 113, 114, and 115, including, but not limited to:

a.all legal and equitable remedies available to enforce the provisions of this Consent Decree;

b.all legal and equitable remedies available to address any imminent and substantial endangerment to the public health or welfare or the environment arising at, or posed by, the Pipeline Facilities, whether related to the violations addressed in this Consent Decree or otherwise;

c.liability for recovery of costs, injunctive relief, or penalties under federal or state laws, regulations, or permit conditions not expressly included within Paragraphs 113, 114, and 115;

d.liability for damages for injury to, destruction of, or loss of natural resources and for the costs of any natural resource damage assessments resulting from releases or threatened releases of hazardous substances that are not the result of the Blacktail Creek Discharge; and

e.criminal liability.

121.Special Reservations Regarding Natural Resource Damages. Notwithstanding any

other provision of this Decree, the United States and the State each reserve the right to institute proceedings against Defendants in this action or in a new action seeking recovery of Natural Resource Damages if conditions are discovered or information is received, not known to the Trustees at the time of lodging of this Decree, that indicates that there is injury to, destruction of, or loss of natural resources of a type unknown, or of a magnitude greater than was known, by the Trustees as of the date of lodging of this Decree. For purposes of this Paragraph, information and conditions known to the Trustees relating to the Site as of the date of lodging of this Decree shall include only the information and conditions set forth in the DOI and State files for the Site as of the date of lodging of this Decree.

XIX.COVENANTS BY DEFENDANTS

122.Defendants covenant not to sue and agree not to assert any claims or causes of action against the United States or the State, or their contractors or employees, with respect to Natural Resource Damages or this Consent Decree, including but not limited to:

a.any direct or indirect claim for reimbursement relating to Natural Resource Damages or the Blacktail Creek Discharge from either the Oil Spill Liability Trust Fund, as defined in Section 1001(11) of OPA, 33 U.S.C. § 2701(11), or from the Hazardous Substance Superfund based on Sections 106(b)(2), 107, 111, 112, or 113 of CERCLA, 42 U.S.C.

§§ 9606(b)(2), 9607, 9611, 9612, or 9613, or any other provision of law;

b.any claim against the United States or the State pursuant to Sections 107 and 113 of CERCLA, 42 U.S.C. §§ 9607 and 9613, relating to Natural Resource Damages; and

c.any claim against the United States or the State pursuant to Section 311 of the CWA, 33 U.S.C. § 1321.

123.Except as provided in Paragraph 116, these covenants not to sue shall not apply in the event that the United States or the State brings a cause of action or issues an order pursuant to the reservations set forth in Section XVIII (Reservation of Rights by the Plaintiffs), other than in Paragraph 120.a (claims for failure to meet a requirement of the Consent Decree) or Paragraph

120.e (criminal liability), but only to the extent that Defendants’ claims arise from the same response action, response costs, or damages that the United States or the State is seeking pursuant to the applicable reservation.

124.Nothing in this Consent Decree shall be deemed to constitute approval or preauthorization of a claim within the meaning of Section 111 of CERCLA, 42 U.S.C. § 9611, or 40 C.F.R. § 300.700(d).

XX.COSTS

125.The Parties shall bear their own costs of this action, including attorneys’ fees, except that the United States and the State shall be entitled to collect the costs (including attorneys’ fees) incurred in any action necessary to collect any portion of the civil penalty or any stipulated penalties due but not paid by Defendants.

XXI.NOTICES AND SUBMISSIONS

126.Unless otherwise specified in this Decree, whenever notifications, submissions, or communications are required by this Consent Decree, they shall be made in writing and addressed as follows:

a.EPA

By email: Llamozas.Emilio@epa.gov

By mail: Emilio Llamozas

NPDES and Wetlands Enforcement Section (8ENF-W-NW)

1595 Wynkoop Street

Denver, Colorado 80202

b.DOI

By email: jessica_n_johnson@fws.gov

By mail: Jessica Johnson

Environmental Contaminants Specialist

U.S. Fish and Wildlife Service 3425 Miriam Avenue Bismarck, ND 58501

c.USDOJ

By email: eescdcopy.enrd@usdoj.gov

Re: DJ # 90-5-2-1-11253

By mail: EES Case Management Unit

Environment and Natural Resources Division

U.S. Department of Justice

P.O. Box 7611

Washington, D.C. 20044-7611 Re: DJ # 90-5-2-1-11253

d.NDDEQ

By email: krockema@nd.gov

By mail: Karl Rockeman

Director, Division of Water Quality Department of Environmental Quality 918 E Divide Ave

Bismarck, ND 58501

e.NDGF

By email: glink@nd.gov

By mail: Greg Link Division Chief

Conservation and Communications

North Dakota Game and Fish Department 100 N. Bismarck Expressway

Bismarck, ND 58501-5095

f.NDIC

By email: lhelms@nd.gov

By mail: Lynn D. Helms Director

NDIC-DMR-OGD

600 East Boulevard Ave., Dept 405

Bismarck, ND 58505-0840

g.United States. Notice to the United States shall be provided to EPA, DOI,

and USDOJ.

h.Trustees. Notice to the Trustees shall be provided to DOI, NDDEQ, and

NDGF.

i.State. Notice to the State shall be provided to NDDEQ and NDGF.

j.Defendants

By email: james.johnston@summitmidstream.com

By mail: James Johnston

Executive Vice President, General Counsel, Chief Compliance Officer and Secretary

Summit Midstream Partners, LP 910 Louisiana Street, Suite 4200

Houston, Texas 77002

127.Any Party may, by written notice to the other Parties, change its designated notice recipient or notice address provided above.

128.Notices submitted pursuant to this Section shall be deemed submitted upon mailing or transmission by email, unless otherwise provided in this Consent Decree or by mutual agreement of the Parties in writing.

129.With the exception of submissions provided to EPA, all submissions to Plaintiffs under this Consent Decree shall be made electronically. Defendants shall provide hard copies and originals of any such materials upon request. Submissions to EPA shall be made both

electronically and in hard copy.

130.Any supporting documents used in the preparation of submissions to Plaintiffs must be maintained electronically and made available upon request.

XXII.RETENTION OF JURISDICTION

131.The Court shall retain jurisdiction over this case until termination of this Consent Decree for the purpose of resolving disputes arising under this Decree or entering orders modifying this Decree, pursuant to Section XV (Dispute Resolution) or Section XXIII (Modification), or effectuating or enforcing compliance with the terms of this Decree.

XXIII.MODIFICATION

132.The terms of this Consent Decree, including any attached appendices, may be modified only by a subsequent written agreement signed by all the Parties. Where the modification constitutes a material change to this Decree, it shall be effective only upon approval by the Court.

133.Any disputes concerning modification of this Decree shall be resolved pursuant to Section XV (Dispute Resolution), provided, however, that, instead of the burden of proof provided by Paragraph 105, the Party seeking the modification bears the burden of demonstrating that it is entitled to the requested modification in accordance with Federal Rule of Civil Procedure 60(b).

XXIV.TERMINATION

134.Request for Partial Termination. Defendants may serve upon Plaintiffs a Request

for Partial Termination of the relevant Consent Decree requirements after making all payments required by Section VIII (Natural Resource Damages) and Section VI (Civil Penalty); paying any accrued stipulated penalties as required by Section XIII (Stipulated Penalties); complying

with all applicable requirements under Section XII (Reporting Requirements); and demonstrating one of the following:

a.A three-year period of continuous satisfactory compliance with Section X (Specific Compliance Requirements); or

b.Completion of requirements in Section XI (Remediation Measures).

135.Request for Consent Decree Termination. Defendants may serve upon Plaintiffs a

Request for Consent Decree Termination after: (a) making all payments required by Section VIII (Natural Resource Damages) and Section VI (Civil Penalty); (b) paying any accrued stipulated penalties as required by Section XIII (Stipulated Penalties); (c) complying with all applicable requirements under Section XII (Reporting Requirements); and (d) meeting the requirements of Subparagraphs 134.a and 134.b.

136.Each Request for Partial Termination or Request for Consent Decree Termination must include all supporting documentation necessary to demonstrate compliance with applicable requirements of this Section XXIV (Termination).

137.Following receipt by Plaintiffs of any Request for Termination, the Parties shall confer informally concerning the Request and any disagreement that the Parties may have as to whether Defendants have satisfactorily complied with the requirements for partial or full termination of this Consent Decree. If the United States and the State agree that the Decree may be terminated in part or in full, the Parties shall submit, for the Court’s approval, a joint stipulation for partial or complete termination of the Decree, as applicable.

138.If the United States and the State do not agree that the Decree may be terminated in part or in full, Defendants may invoke Dispute Resolution under Section XV. However, Defendants shall not seek Dispute Resolution of any dispute regarding termination until 60 Days

after service of its Request for Termination.

XXV.PUBLIC PARTICIPATION

139.This Consent Decree shall be lodged with the Court for a period of not less than 30 Days for public notice and comment in accordance with 28 C.F.R. § 50.7. The United States reserves the right to withdraw or withhold its consent if the comments regarding the Consent Decree disclose facts or considerations indicating that the Consent Decree is inappropriate, improper, or inadequate. Defendants consent to entry of this Consent Decree without further notice and agree not to withdraw from or oppose entry of this Consent Decree by the Court or to challenge any provision of the Decree, unless the United States has notified Defendants in writing that it no longer supports entry of the Decree.

XXVI.SIGNATORIES/SERVICE

140.Each undersigned representative of Defendants and the State, and the Deputy Assistant Attorney General for the Environment and Natural Resources Division of the Department of Justice identified on the DOJ signature page below, certifies that he or she is fully authorized to enter into the terms and conditions of this Consent Decree and to execute and legally bind the Party he or she represents to this document.

141.This Consent Decree may be signed in counterparts, and its validity shall not be challenged on that basis. Defendants agree to accept service of process by mail with respect to all matters arising under or relating to this Consent Decree and to waive the formal service requirements set forth in Rules 4 and 5 of the Federal Rules of Civil Procedure and any applicable Local Rules of this Court including, but not limited to, service of a summons. Defendants need not file an answer to the complaint in this action unless or until the Court expressly declines to enter this Consent Decree.

XXVII.INTEGRATION

142.This Consent Decree constitutes the final, complete, and exclusive agreement and understanding among the Parties with respect to the settlement embodied in the Decree and supersedes all prior agreements and understandings, whether oral or written, concerning the settlement embodied herein. Other than deliverables that are subsequently submitted and approved pursuant to this Decree, the Parties acknowledge that there are no representations, agreements, or understandings relating to the settlement other than those expressly contained in this Consent Decree.

XXVIII.APPENDICES

143.The following Appendices are attached to and part of this Consent Decree: Appendix A: Maps of Existing Pipelines

Appendix B: Compliance-Focused Environmental Management System Elements Appendix C: Map of the Blacktail Creek Remediation Site

Appendix D: Ability to Pay Information Requests

XXIX.26 U.S.C. SECTION 162(f)(2)(A)(ii) IDENTIFICATION

144.For purposes of the identification requirement of Section 162(f)(2)(A)(ii) of the Internal Revenue Code, 26 U.S.C. § 162(f)(2)(A)(ii), and 26 C.F.R. § 162-21(b)(2), performance of Section III (Applicability), Paragraph 6; Section VIII (Natural Resource Damages), Paragraphs 20-22; Section IX (General Compliance Requirements), Paragraphs 26.a-26.c, 27-28; Section X (Specific Compliance Requirements), Paragraphs 31-60, 64, 67; Section XI (Remediation Measures), Paragraphs 68-70; Section XII (Reporting Requirements), Paragraphs 72-74, 76, 78; and Section XVI (Information Collection and Retention), Paragraphs 107-110; and the $1,000,000 paid pursuant to Section VIII (Natural Resource Damages), Paragraph 22, are

restitution, remediation, or required to come into compliance with law.

XXX.FINAL JUDGMENT

145.Upon approval and entry of this Consent Decree by the Court, this Consent Decree shall constitute a final judgment of the Court as to the United States, the State, and Defendants.

Dated and entered this day of , 2021

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UNITED STATES DISTRICT JUDGE

The Undersigned Party Enters into this Consent Decree in United States of America and State of North Dakota v. Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC.

FOR THE UNITED STATES OF AMERICA

BRUCE S. GELBER

Deputy Assistant Attorney General Environment and Natural Resources Division

U.S. Department of Justice

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Date LAURA A. THOMS, Bar No. DC 488784

Senior Attorney

DEVON A. AHEARN, Bar No. CA 307275

Trial Attorney

Environmental Enforcement Section Environment & Natural Resources Division United States Department of Justice

P.O. Box 7611 Washington, D.C. 20044

Tel: 202-305-0260 (L. Thoms) 202-514-2717 (D. Ahearn)

Email: laura.thoms@usdoj.gov devon.ahearn@usdoj.gov

The Undersigned Party Enters into this Consent Decree in United States of America and State of North Dakota v. Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC.

FOR THE U.S. ENVIRONMENTAL PROTECTION AGENCY

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Date SUZANNE J. BOHAN

Assistant Regional Administrator Office of Enforcement, Compliance and Environmental Justice

U.S. Environmental Protection Agency, Region 8

Date SHELDON H. MULLER

Senior Attorney

Legal Enforcement Program

Office of Enforcement, Compliance and Environmental Justice

U.S. Environmental Protection Agency, Region 8

The Undersigned Party Enters into this Consent Decree in United States of America and State of North Dakota v. Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC.

FOR THE U.S. ENVIRONMENTAL PROTECTION AGENCY

Date [INSERT]

Assistant Administrator

Office of Enforcement and Compliance Assurance

U.S. EPA

Mail Code 2243A

1200 Pennsylvania Ave., N.W. Washington, D.C. 20460

Date CATHLEEN GILLEN TIERNEY

Senior Attorney

Office of Enforcement and Compliance Assurance

U.S. EPA

Mail Code 2243A

1200 Pennsylvania Ave., N.W. Washington, D.C. 20460

The Undersigned Party Enters into this Consent Decree in United States of America and State of North Dakota v. Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC.

FOR THE STATE OF NORTH DAKOTA:

Date WAYNE K. STENEHJEM

Attorney General

State Bar ID No. 03442 Office of Attorney General

600 East Boulevard Avenue, Dept. 125

Bismarck, ND 58505-0040

Date MARGARET I. OLSON

Assistant Attorney General State Bar ID No. 06352 Office of Attorney General 500 North 9th Street Bismarck, ND 58501-4509

The Undersigned Party Enters into this Consent Decree in United States of America and State of North Dakota v. Summit Midstream Partners, LLC and Meadowlark Midstream Company, LLC.

FOR SUMMIT MIDSTREAM PARTNERS, LLC; MEADOWLARK MIDSTREAM COMPANY, LLC; and SUMMIT OPERATING SERVICES COMPANY, LLC:

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Date

APPENDIX A

EXISTING PIPELINES MAPS

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APPENDIX B

COMPLIANCE-FOCUSED ENVIRONMENTAL MANAGEMENT SYSTEM ELEMENTS

United States, et al. v. Summit Midstream Partners, LLC, et al

1.Environmental Policy

a.This policy, upon which the EMS is based, must clearly communicate management commitment to achieving compliance with applicable federal, state, and local environmental statutes, regulations, enforceable agreements, and permits (hereafter, “environmental requirements”), minimizing risks to the environment from unplanned or unauthorized releases of hazardous or harmful contaminants, and continual improvement in environmental performance. The policy must also state management’s intent to provide adequate personnel and other resources for the EMS.

2.Organization, Personnel, and Oversight of EMS

a.Identifies and defines specific duties, roles, responsibilities, and authorities of key environmental staff in implementing and sustaining the EMS (e.g., could include position descriptions and/or performance standards for all environmental department personnel, and excerpts from others having specific environmental duties, and regulatory compliance responsibilities).

b.Includes organization charts that identify units, line management, and other individuals having environmental duties and regulatory compliance responsibilities.

c.Includes ongoing means of communicating environmental issues and information among the various levels and functions of the organization, to include all persons working for or on behalf of the organization (e.g., on-site service providers and contractors who function as de facto employees), and for receiving and addressing their concerns.

3.Accountability and Responsibility

a.Specifies accountability and environmental responsibilities of organization’s managers, and managers of other organizations acting on its behalf, for environmental protection and risk reduction measures, assuring compliance, required reporting to regulatory agencies, and corrective actions implemented in their area(s) of responsibility.

b.Describes incentive programs for managers and employees to perform in accordance with compliance policies, standards, and procedures.

c.Describes potential consequences for departure from specified operating


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procedures, including liability for civil/administrative penalties imposed as a result of noncompliance.

4.Environmental Requirements

a.Describes process for identifying potentially applicable environmental requirements; interpreting their applicability to specific operations, emissions, and waste streams; and effectively communicating those applicable environmental requirements to affected persons working for or on behalf of the organization.

b.Describes a process for developing, implementing and maintaining ongoing internal compliance monitoring to ensure that Pipeline Facility activities conform to applicable environmental requirements. Compliance monitoring shall include inspections and measurements, as appropriate.

c.Describes procedures for prospectively identifying and obtaining information about changes and proposed changes in environmental requirements, and incorporating those changes into the EMS (i.e., regulatory “change management”).

d.Describes a procedure for communicating with regulatory agencies regarding environmental requirements and regulatory compliance.

5.Assessment, Prevention, and Control

a.Identifies an ongoing process for assessing operations for the purposes of preventing, controlling, or minimizing reasonably foreseeable releases, environmental process hazards, and risks of noncompliance with environmental requirements. This process shall include identifying operations and waste streams where equipment malfunctions and deterioration, and/or operator errors or deliberate malfeasance, are causing, or have the potential to cause: (1) unplanned or unauthorized releases of hazardous or harmful contaminants to the environment, (2) a threat to human health or the environment, or (3) noncompliance with environmental requirements.

b.Describes process for identifying operations and activities where documented operating criteria, such as standard operating procedures (SOPs), are needed to prevent noncompliance or unplanned/unauthorized releases of hazardous or harmful contaminants, and defines a uniform process for developing, approving and implementing the documented operating criteria.

c.Describes a system for conducting and documenting routine, objective, self- inspections by department supervisors and trained staff, especially at locations identified by the process described in (a) above, to check for malfunctions, deterioration, worker adherence to operating criteria, unusual situations, and unauthorized or unplanned releases.

d.Describes a “management of change” process to ensure identification and


2

consideration of environmental requirements, the environmental aspects/impacts, and potential operator errors or deliberate malfeasance during planning, design, and operation of ongoing, new, and/or changing buildings, processes, equipment, maintenance activities, and products.

6.Environmental Incident and Non-Compliance Investigations

a.Describes standard procedures and requirements for internal and external reporting of environmental incidents and noncompliance with environmental requirements.

b.Establishes procedures for investigation, and prompt and appropriate correction of noncompliance. The investigation process includes root-cause analysis of identified problems to aid in developing the corrective actions.

c.Describes a system for development, tracking, and effectiveness verification of corrective and preventative actions.

7.Environmental Training, Awareness, and Competence

a.Identifies specific education and training required for organization personnel or those acting on its behalf, as well as process for documenting training provided

b.Describes program to ensure that organization employees or those acting on its behalf are aware of its environmental policies and procedures, environmental requirements, and their roles and responsibilities within the environmental management system.

c.Describes program for ensuring that personnel responsible for meeting and maintaining compliance with environmental requirements are competent based on appropriate education, training, and/or experience.

d.Identifies training on how to recognize operations and waste streams where equipment malfunctions and deterioration, and/or operator errors or deliberate malfeasance, are causing, or have the potential to cause: (1) unplanned or unauthorized releases of hazardous or harmful contaminants to the environment,

(2) a threat to human health or the environment, or (3) noncompliance with environmental requirements.

8.Environmental Planning and Organizational Decision-Making

a.Describes how environmental planning will be integrated into organizational decision-making, including plans and decisions on capital improvements, product and process design, training programs, and maintenance activities.

b.Requires establishing, on an annual basis, written targets, objectives, and action plans for improving environmental performance, by at least each operating organizational subunit with environmental responsibilities, as appropriate,


3

including those for contractor operations conducted at the Pipeline Facility, and how specified actions will be tracked and progress reported. Targets and objectives must include actions that reduce the risk of noncompliance with environmental requirements and minimize the potential for unplanned or unauthorized releases of hazardous or harmful contaminants.

9.Maintenance of Records and Documentation

a.Identifies the types of records developed in support of the EMS (including audits and reviews), who maintains them and, where appropriate, security measures to prevent their unauthorized disclosure, and protocols for responding to inquiries and requests for release of information.

b.Specifies the data management systems for any internal waste tracking, environmental data, and hazardous waste determinations.

c.Specifies document control procedures.

10.Pollution Prevention

a.Describes an internal process or procedure for preventing, reducing, recycling, reusing, and minimizing waste and emissions, including incentives to encourage material substitutions. Also includes mechanisms for identifying candidate materials to be addressed by the pollution prevention program and tracking progress.

11.Continuing Program Evaluation and Improvement

a.Describes a program for periodic (at least annually) evaluation of the EMS, which specifies a process for translating assessment results into EMS improvements. The program shall include communicating findings and action plans to affected organization employees or those acting on its behalf.

b.Describes a program for periodic audits (at least annually) of Pipeline Facility compliance with environmental requirements by an independent auditor(s). Audit results are reported to upper management and instances of noncompliance are addressed through the process described in element 6 above.

12.Public Involvement/Community Outreach

a.Describes a program for ongoing community education and involvement in the environmental aspects of the organization's operations and general environmental awareness.


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APPENDIX C

BLACKTAIL REMEDIATION SITE MAP

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APPENDIX D

ABILITY TO PAY INFORMATION REQUESTS

I.July 27, 2020 Information Request

1.Summit Operating Services Company, LLC. Provide an updated version of the organizational chart provided in EPA308-0000055 that includes Summit Operating Services Company, LLC. Please identify the companies on the chart to which Summit Operating Services Company, LLC provides employees.

2.Financial statements. Provide audited financial statements from 2015 to the present, (including balance sheet, income statement, statement of cash flows, notes, auditor’s opinion, and any supplemental schedules) for the following companies:

a.Meadowlark Midstream Company, LLC;

b.Summit Midstream OpCo, LP;

c.Summit Midstream Holdings, LLC;

d.Summit Midstream Partners Holdings, LLC; and

e.Summit Midstream Partners, LLC

If audited statements are not prepared, unaudited statements are acceptable. If any statements are prepared on a consolidated basis, provide copies of all consolidating schedules.

3.Federal tax returns. Provide signed copies of the federal income tax returns from 2015 to the present, complete with all information submitted to the Internal Revenue Service for the following companies:

a.Meadowlark Midstream Company, LLC;

b.Summit Midstream OpCo, LP;

c.Summit Midstream Partners, LP;

d.Summit Midstream Holdings, LLC;

e.Summit Midstream Partners Holdings, LLC; and

f.Summit Midstream Partners, LLC

Note that if a company does not file federal income taxes, submit copies of the tax returns filed by the entity or individual for which the tax consequences of the company are reflected.

4.Projections. Provide all documents prepared since January 1, 2019 that relate to the following companies’ future financial performance, including projected financial performance presented in solicitations seeking additional debt and/or equity financing:

a.Meadowlark Midstream Company, LLC;

b.Summit Midstream OpCo, LP;

c.Summit Midstream Partners, LP;

d.Summit Midstream Holdings, LLC;

e.Summit Operating Services Company, LLC;

f.Summit Midstream Partners Holdings, LLC; and

g.Summit Midstream Partners, LLC

Relevant documents should include but not be limited to Excel spreadsheets in fully executable format complete with all metadata, formulas and linkages to other spreadsheets together with any linked spreadsheets; presentations to Boards; presentations to current or prospective debtholders, presentations to current or prospective equity holders, and memoranda.

5.Board/Member Presentations. Provide all materials provided to the Boards and/or equity holders relating to the January 2015 pipeline rupture for the following companies:

a.Meadowlark Midstream Company, LLC;

b.Summit Midstream OpCo, LP;

c.Summit Midstream Partners, LP;

d.Summit Midstream Holdings, LLC;

e.Summit Operating Services Company, LLC;

f.Summit Midstream Partners Holdings, LLC; and

g.Summit Midstream Partners, LLC.

6.Debt agreements. Provide copies of all debt agreements, both intercompany and third-party, to which the following companies currently are a party:

a.Meadowlark Midstream Company, LLC;

b.Summit Midstream OpCo, LP;

c.Summit Midstream Partners, LP;

d.Summit Midstream Holdings, LLC;

e.Summit Operating Services Company, LLC;

f.Summit Midstream Partners Holdings, LLC; and

g.Summit Midstream Partners, LLC.

Provide all appendices, attachments, and any other related materials, as well as any amendments to each debt agreement. Describe the current status of each debt agreement, including the amount outstanding, the collateralized assets, and the amount owed on and frequency of debt service payments.

7.Information provided to Debtholders. Provide all information provided to current or prospective debtholders from January 2015 to the present for the following companies:

a.Meadowlark Midstream Company, LLC;

b.Summit Midstream OpCo, LP;

c.Summit Midstream Partners, LP;

d.Summit Midstream Holdings, LLC;

e.Summit Operating Services Company, LLC;

f.Summit Midstream Partners Holdings, LLC; and

g.Summit Midstream Partners, LLC.

8.Intercompany Transactions. Describe all transactions that have occurred between Meadowlark Midstream Company, LLC and any affiliate since January 1, 2015 and provide:

a.For affiliate, brief description of the nature of the relationship with Meadowlark Midstream Company LLC, nature of the transactions, and dates of the transactions; and

b.Intercompany agreement governing the transactions, complete with all attachments, updates, and addenda. If written agreements do not exist, describe all material terms of the agreement.

For purposes of this question, affiliates include (i) entities owning equity in Meadowlark Midstream Company LLC directly or indirectly, (ii) entities owned in whole or in part by Meadowlark Midstream Company LLC, directly or indirectly, (iii) entities with substantially the same legal or beneficial ownership as Meadowlark Midstream Company LLC, and (iv) entities directed or managed by persons who are either themselves directors, officers, or members of Meadowlark Midstream Company LLC, or who are related to directors, officers, or members of Meadowlark Midstream Company LLC.

9.Insurance. For any claim made with insurers in connection with the pipeline rupture into Blacktail Creek that was reported in January 2015, provide:

a.All summaries of the status of the claims;

b.A description of each claim including but not limited to the insurer, policy number, policy holder, type of insurance policy, coverage sought, disposition of claim, date of settlement, coverage paid, and current status; and

c.Copy of insurance policy complete with all attachments, updates, and addenda.

10.Compensation. For each year from 2015 to the present, whether employed directly or through Summit Operating Services Company, LLC or its predecessor, provide for of the five most highly compensated employees (including officers) of Meadowlark Midstream Company, LLC; Summit Midstream OpCo, LP; Summit Midstream Partners, LP; Summit Midstream Holdings, LLC; Summit Midstream Partners Holdings, LLC; and Summit Midstream Partners, LLC:

a.Name, title, and brief description of responsibilities;

b.Employer; and

c.Salary, bonus, perquisites, and total compensation.

II.December 11, 2020 Request

1.Complete “Marmon Follow Up Slides” presentation and underlying model.

a.Provide a complete version of the presentation from which the “Marmon Follow Up Slides” originated.

b.Provide the model used to generate SMLP’s financial projections (e.g., the “Detailed Financial Outlook” projections presented on slides 2 and 31 to 33 of the “Marmon Follow Up Slides v_4” presentation). Provide a fully executable version of the model in excel, complete with all tabs, formulas, links, and linked spreadsheets (also in fully executable format).

2.Board materials.

a.Provide all materials provided to the Board of Directors since the Q2 2020 meeting regarding SMLP’s financial condition and outlook to the present.

b.Provide a fully executable version of the excel model used to generate the most recent materials provided to the Board of Directors, complete with all tabs, formulas, links, and linked spreadsheets (also in fully executable format).

3.Materials provided to debtholders (including parties to negotiations regarding the revolving credit agreement).

a.Provide all correspondence, information, presentations, and any other materials provided or presented to all debtholders from May 29, 2020 to the present.

b.Provide an executable version of the most recent excel model presented to debtholders, complete with all tabs, formulas, links, and linked spreadsheets (also in fully executable format).

III.March 5, 2021 Request

1.Current version of Summit’s financial projection model.

2.Current version of any financial guidance or projections that Summit has generated for years 2023-2025.

3.Correspondence with Summit’s prospective lenders or any other documentation that supports Summit’s projection of likely total net debt to EBITDA ratio in Summit’s future revolving credit facility.

Document

EXHIBIT 31.1

CERTIFICATIONS

I, Heath Deneke, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Summit Midstream Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


Date:	August 6, 2021	/s/ Heath Deneke
		Heath Deneke President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)

EX 31.1-1

Document

EXHIBIT 31.2

CERTIFICATIONS

I, Marc D. Stratton, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Summit Midstream Partners, LP;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


Date:	August 6, 2021	/s/ Marc D. Stratton
		Marc D. Stratton Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)

EX 31.2-1

Document

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Summit Midstream Partners, LP (the “Registrant”) for the quarterly period ended June 30, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Heath Deneke, as President, Chief Executive Officer and Director of Summit Midstream GP, LLC, the general partner of the Registrant, and Marc D. Stratton, as Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC, the general partner of the Registrant, each hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.


/s/ Heath Deneke
Name:						Heath Deneke
Title:						President, Chief Executive Officer and Director of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)
Date:						August 6, 2021


/s/ Marc D. Stratton
Name:						Marc D. Stratton
Title:						Executive Vice President and Chief Financial Officer of Summit Midstream GP, LLC (the general partner of Summit Midstream Partners, LP)
Date:						August 6, 2021

EX 32.1-1