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SMLP Summit Midstream Partners

Filed: 8 Aug 21, 8:00pm
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
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from        to        
Commission file number: 001-35666
Summit Midstream Partners, LP
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction 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 classTrading Symbol(s)Name of each exchange on which registered
Common UnitsSMLPNew 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).
xYesoNo
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 filerAccelerated filer
Non-accelerated filerSmaller 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.
ClassAs of August 1, 2021
Common Units6,744,926 units


TABLE OF CONTENTS

1

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
ASUAccounting Standards Update
Bison MidstreamBison Midstream, LLC
Board of Directorsthe 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 MidstreamDFW Midstream Services LLC
DJ BasinDenver-Julesburg Basin
Double EDouble 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
EppingEpping Transmission Company, LLC
EPUearnings or loss per unit
FASBFinancial Accounting Standards Board
Finance Corp.Summit Midstream Finance Corp.
GAAPaccounting principles generally accepted in the United States of America
General PartnerSummit Midstream GP, LLC
GPgeneral partner
Grand RiverGrand 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
hubgeographic location of a storage facility and multiple pipeline interconnections
LIBORLondon Interbank Offered Rate
Mbbl/done thousand barrels per day
Meadowlark MidstreamMeadowlark Midstream Company, LLC
MMcf/done million cubic feet per day
Mountaineer MidstreamMountaineer Midstream Company, LLC
MVCminimum 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&PNiobrara Gathering and Processing system
NYSENew York Stock Exchange
OCCOhio Condensate Company, L.L.C.
OGCOhio Gathering Company, L.L.C.
Ohio GatheringOhio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C.
OpCoSummit Midstream OpCo, LP
playa proven geological formation that contains commercial amounts of hydrocarbons
Permian FinanceSummit Midstream Permian Finance, LLC
2

Permian HoldcoSummit Permian Transmission Holdco, LLC
Permian Transmission Credit FacilityCredit 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 Dividethe Polar and Divide system; collectively Polar Midstream and Epping
produced waterwater from underground geologic formations that is a by-product of natural gas and
crude oil production
Revolving Credit Facilitythe 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
SECSecurities 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 NotesThe 5.5% Senior Notes and the 5.75% Senior Notes, collectively
Series A Preferred UnitsSeries A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
shortfall paymentthe payment received from a counterparty when its volume throughput does not
meet its MVC for the applicable period
SMLPSummit Midstream Partners, LP
SMLP LTIPSMLP Long-Term Incentive Plan
SMP HoldingsSummit Midstream Partners Holdings, LLC, also known as SMPH
SMPH Term Loanthe 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 HoldingsSummit Midstream Holdings, LLC
Summit InvestmentsSummit Midstream Partners, LLC
Summit MarketingSummit Midstream Marketing, LLC
Summit PermianSummit Midstream Permian, LLC
Summit Permian IISummit Midstream Permian II, LLC
Summit Permian
Transmission
Summit Permian Transmission, LLC
Summit UticaSummit Midstream Utica, LLC
the PartnershipSummit 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 volumethe 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
3

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
wellheadthe 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

4

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 cash314 
Accounts receivable, net61,233 61,932 
Other current assets11,090 4,623 
Total current assets79,848 82,099 
Property, plant and equipment, net1,768,897 1,817,546 
Intangible assets, net186,525 199,566 
Investment in equity method investees433,440 392,740 
Other noncurrent assets5,335 7,866 
TOTAL ASSETS$2,474,045 $2,499,817 
LIABILITIES AND CAPITAL
Trade accounts payable$14,824 $11,878 
Accrued expenses10,092 13,036 
Deferred revenue10,593 9,988 
Ad valorem taxes payable5,395 9,086 
Accrued compensation and employee benefits5,847 9,658 
Accrued interest8,007 8,007 
Accrued environmental remediation1,959 1,392 
Current portion of long-term debt762,000 
Other current liabilities28,209 5,363 
Total current liabilities846,926 68,408 
Long-term debt, excluding current portion539,099 1,347,326 
Noncurrent deferred revenue44,857 48,250 
Noncurrent accrued environmental remediation1,192 1,537 
Other noncurrent liabilities38,994 21,747 
Total liabilities1,471,068 1,487,268 
Commitments and contingencies (Note 13)
00
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' capital905,298 922,891 
TOTAL LIABILITIES AND CAPITAL$2,474,045 $2,499,817 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
5

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees$74,233 $73,911 $144,580 $157,703 
Natural gas, NGLs and condensate sales16,416 10,683 37,180 24,463 
Other revenues9,392 7,413 17,599 14,744 
Total revenues100,041 92,007 199,359 196,910 
Costs and expenses:
Cost of natural gas and NGLs16,626 6,088 37,102 14,313 
Operation and maintenance17,507 21,152 34,100 42,963 
General and administrative29,360 12,786 39,938 29,347 
Depreciation and amortization28,364 29,630 56,875 59,296 
Transaction costs450 1,207 217 1,218 
Gain on asset sales, net(4)(281)(140)(166)
Long-lived asset impairments33 654 1,525 4,475 
Total costs and expenses92,336 71,236 169,617 151,446 
Other income (expense), net(2,334)276 (2,284)(151)
Loss on ECP Warrants(12,159)(13,634)
Interest expense(15,502)(21,990)(29,455)(45,818)
Gain on early extinguishment of debt54,235 54,235 
Income (loss) before income taxes and equity method investment income(22,290)53,292 (15,631)53,730 
Income tax benefit248 389 262 402 
Income from equity method investees2,304 3,040 4,619 6,351 
Net income (loss)$(19,738)$56,721 $(10,750)$60,483 
Net income attributable to Subsidiary Series A Preferred Units(4,089)(1,397)(8,021)(2,342)
Net loss attributable to noncontrolling interest1,393 3,274 
Net income (loss) attributable to Summit Midstream Partners, LP$(23,827)$56,717 $(18,771)$61,415 
Less: net income attributable to Series A Preferred Units(3,849)(7,125)(8,136)(14,250)
Add: deemed contribution from 2021 Preferred Exchange Offer8,326 8,326 
Net income (loss) attributable to common limited partners$(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 – basic6,656 2,977 6,392 2,999 
Common units – diluted6,656 3,116 6,392 3,088 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
6

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
Noncontrolling InterestPartners' Capital
Series A Preferred UnitsCommon
Noncontrolling
Interests
Series A Preferred UnitsPartners' CapitalTotal
(In thousands)
Partners' capital, January 1, 2021$$$174,425 $748,466 $922,891 
Net income— — 4,287 769 5,056 
Unit-based compensation— — — 1,967 1,967 
Tax withholdings and associated
payments on vested SMLP LTIP
awards
— — — (1,274)(1,274)
Partners' capital, March 31, 2021178,712 749,928 928,640 
Net income (loss)— — 3,849 (27,676)(23,827)
Unit-based compensation— — — 1,048 1,048 
Tax withholdings and associated
payments on vested SMLP LTIP
awards
— — — (98)(98)
Tax withholdings on 2021 Preferred Exchange Offer— — — (465)(465)
Effect of 2021 Preferred Exchange Offer, inclusive of an $8.3 million deemed contribution to common unit holders (Note 9)— — (20,654)20,654 
Partners' capital, June 30, 2021$$$161,907 $743,391 $905,298 
7

Noncontrolling InterestPartners' Capital
Series A Preferred UnitsCommon Noncontrolling InterestsSeries A Preferred UnitsPartners' CapitalTotal
(In thousands)
Partners' capital, January 1, 2020$293,616 $186,070 $$305,550 $785,236 
Net income (loss)7,125 (1,881)— (2,427)2,817 
Net cash distributions to SMLP unitholders— (6,037)— — (6,037)
Unit-based compensation— 2,723 — — 2,723 
Effect of common unit issuances under
SMLP LTIP
— 2,322 — (2,322)
Tax withholdings and associated
payments on vested SMLP LTIP
awards
— (984)— — (984)
Partners' capital, March 31, 2020300,741 182,213 300,801 783,755 
Net income (loss)4,750 (1,393)2,375 49,592 55,324 
Unit-based compensation— 1,331 — 515 1,846 
Tax withholdings and associated
payments on vested SMLP LTIP
awards
— (34)— (28)(62)
GP Buy-In Transaction assumption of noncontrolling interest in SMLP(305,491)(182,117)305,491 182,117 
Repurchase of common units under GP Buy-In Transaction— — — (44,078)(44,078)
Other— — — (61)(61)
Partners' capital, June 30, 2020$$$307,866 $488,858 $796,724 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
8

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended June 30,
20212020
(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 amortization57,344 59,766 
Noncash lease expense519 1,557 
Amortization of debt issuance costs3,447 3,136 
Unit-based and noncash compensation3,015 4,569 
Income from equity method investees(4,619)(6,351)
Distributions from equity method investees13,116 12,749 
Gain on asset sales, net(140)(166)
Loss on ECP Warrants13,634 
Unsettled loss on interest rate swaps2,692 
Gain on extinguishment of debt(54,235)
Long-lived asset impairment1,525 4,475 
Changes in operating assets and liabilities:
Accounts receivable(1,993)20,219 
Trade accounts payable2,989 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, net15,555 (4,410)
Net cash provided by operating activities86,217 105,371 
Cash flows from investing activities:
Capital expenditures(5,962)(27,426)
Proceeds from asset sale8,000 
Investment in Double E equity method investee(48,943)(79,728)
Other, net217 
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 Facility53,500 — 
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 costs48,710 
Borrowings under ECP Loans35,000 
Purchase of common units in GP Buy-In Transaction(41,778)
Debt issuance costs(5,179)(1,080)
Proceeds from asset sale260 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 period15,544 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.
9

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.
10

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
11

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.
20212022202320242025Thereafter
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 feesNatural gas, NGLs and condensate salesOther revenuesTotal
(in thousands)
Reportable Segments:
Utica Shale$11,349 $$$11,349 
Williston Basin12,516 8,201 4,242 24,959 
DJ Basin5,891 305 1,856 8,052 
Permian Basin2,262 6,875 121 9,258 
Piceance Basin25,527 1,025 1,233 27,785 
Barnett Shale10,076 10 1,012 11,098 
Marcellus Shale6,612 6,612 
Total reportable segments74,233 16,416 8,464 99,113 
Corporate and Other928 928 
Total$74,233 $16,416 $9,392 $100,041 
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Six Months Ended June 30, 2021
Gathering services and related feesNatural gas, NGLs and condensate salesOther revenuesTotal
(in thousands)
Reportable Segments:
Utica Shale$19,920 $$$19,920 
Williston Basin25,149 20,428 8,749 54,326 
DJ Basin12,154 415 2,560 15,129 
Permian Basin4,461 13,393 237 18,091 
Piceance Basin50,311 2,878 2,409 55,598 
Barnett Shale19,772 66 2,072 21,910 
Marcellus Shale12,813 12,813 
Total reportable segments144,580 37,180 16,027 197,787 
Corporate and Other1,572 1,572 
Total$144,580 $37,180 $17,599 $199,359 
Three Months Ended June 30, 2020
Gathering services and related feesNatural gas, NGLs and condensate salesOther revenuesTotal
(in thousands)
Reportable Segments:
Utica Shale$11,538 $$$11,538 
Williston Basin12,407 3,131 2,776 18,314 
DJ Basin5,228 71 993 6,292 
Permian Basin2,711 4,222 126 7,059 
Piceance Basin26,222 401 1,096 27,719 
Barnett Shale9,877 2,858 1,778 14,513 
Marcellus Shale5,928 5,928 
Total reportable segments73,911 10,683 6,769 91,363 
Corporate and Other644 644 
Total$73,911 $10,683 $7,413 $92,007 
Six Months Ended June 30, 2020
Gathering services and related feesNatural gas, NGLs and condensate salesOther revenuesTotal
(in thousands)
Reportable Segments:
Utica Shale$18,500 $$$18,500 
Williston Basin36,204 7,455 5,918 49,577 
DJ Basin12,083 141 2,027 14,251 
Permian Basin5,022 8,734 313 14,069 
Piceance Basin53,411 1,404 2,161 56,976 
Barnett Shale20,320 6,729 3,038 30,087 
Marcellus Shale12,163 12,163 
Total reportable segments157,703 24,463 13,457 195,623 
Corporate and Other1,287 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 
Additions4,985 
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, 2021December 31, 2020
(In thousands)
Gathering and processing systems and related equipment$2,221,834 $2,213,501 
Construction in progress45,780 60,443 
Land and line fill10,440 10,440 
Other59,683 61,340 
Total2,337,737 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,
2021202020212020
(In thousands)
Depreciation expense$21,318 $21,664 $42,784 $43,362 
Capitalized interest149 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 distributions2,314 
Basis difference212,259 
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: additions4,074 
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: additions667 
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, 2021December 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 debt1,301,099 1,347,326 
Less current maturities of:
Revolving Credit Facility762,000 
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 0 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, 2020Total
20222025
Senior NotesSenior 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, 2021December 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 Notes257,310 237,625 257,138 168,002 
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, 20206,110,092 
2021 Preferred Exchange Offer, net of shares withheld for taxes538,715 
Common units issued for SMLP LTIP, net96,119 
Units, June 30, 20216,744,926 
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 distributions3,013 
Redemption accretion5,008 
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
18

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 $15.5 million, were accounted for as a liability instrument and recorded within other current liabilities on the unaudited condensed consolidated balance sheets. The value as of June 30, 2021 approximates the settlement value on August 5, 2021, the date in which the ECP Warrants were exercised by their holders. See Note 16 - Subsequent Events for further details.
Cash Distribution Policy. In connection with the GP Buy-In Transaction, the Partnership suspended its cash distributions to holders of its common units, commencing with respect to the quarter ending March 31, 2020. Upon the resumption of distributions, the Partnership Agreement requires that it distribute all available cash, subject to reserves established by its General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under this policy is subject to fluctuations based on the amount of cash the Partnership generates from its business and the decision to make any distribution is determined by the General Partner, taking into consideration the terms of the Partnership Agreement. The Partnership’s last distribution was paid on February 14, 2020, to unitholders of record at the close of business on February 7, 2020.
10. EARNINGS PER UNIT
The following table details the components of EPU.
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(In thousands,
except per-unit amounts)
(In thousands,
except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net income (loss) among limited partner interests:
Net income (loss)$(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 interest1,393 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 Offer8,326 8,326 
Net income (loss) attributable to common limited partners(19,350)$49,592 (18,581)$47,165 
Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic6,656 2,977 6,392 2,999 
Effect of nonvested phantom units139 89 
Weighted-average common units outstanding – diluted6,656 3,116 6,392 3,088 
Net Income (Loss) per limited partner unit:
Common unit – basic$(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,
20212020
(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 6 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 accruals734 
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, 2021December 31, 2020
(In thousands)
Assets (1):
Utica Shale$207,783 $209,425 
Ohio Gathering252,537 259,888 
Williston Basin404,719 425,873 
DJ Basin195,089 199,920 
Permian Basin166,712 165,765 
Piceance Basin555,033 579,800 
Barnett Shale326,446 336,629 
Marcellus Shale173,918 176,441 
Total reportable segment assets2,282,237 2,353,741 
Corporate and Other191,808 146,076 
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,
2021202020212020
(In thousands)(In thousands)
Reportable segment adjusted EBITDA
Utica Shale$10,652 $10,693 $18,372 $16,621 
Ohio Gathering6,841 7,514 13,713 15,453 
Williston Basin9,626 12,727 20,431 28,919 
DJ Basin5,106 4,339 10,453 10,250 
Permian Basin461 1,828 1,170 3,409 
Piceance Basin20,324 21,734 41,358 45,291 
Barnett Shale8,889 8,510 16,905 17,270 
Marcellus Shale5,868 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,
2021202020212020
(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 expense40,264 9,533 48,060 21,610 
Interest expense15,502 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 payments2,291 (3,151)
Adjustments related to capital reimbursement activity(2,225)(237)(3,470)(448)
Unit-based and noncash compensation1,048 1,846 3,015 4,569 
Gain on asset sales, net(4)(281)(140)(166)
Long-lived asset impairment33 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,
2021202020212020
(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 Gathering6,841 7,514 13,713 15,453 
Williston Basin9,626 12,727 20,431 28,919 
DJ Basin5,106 4,339 10,453 10,250 
Permian Basin461 1,828 1,170 3,409 
Piceance Basin20,324 21,734 41,358 45,291 
Barnett Shale8,889 8,510 16,905 17,270 
Marcellus Shale5,868 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 Facility36,000 — 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,
25

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,
2021202020212020
(In thousands)(In thousands)
Revenues:
Gathering services and related fees$74,233 $73,911 $144,580 $157,703 
Natural gas, NGLs and condensate sales16,416 10,683 37,180 24,463 
Other revenues9,392 7,413 17,599 14,744 
Total revenues100,041 92,007 199,359 196,910 
Costs and expenses:
Cost of natural gas and NGLs16,626 6,088 37,102 14,313 
Operation and maintenance17,507 21,152 34,100 42,963 
General and administrative (2)
29,360 12,786 39,938 29,347 
Depreciation and amortization28,364 29,630 56,875 59,296 
Transaction costs450 1,207 217 1,218 
Gain on asset sales, net(4)(281)(140)(166)
Long-lived asset impairment33 654 1,525 4,475 
Total costs and expenses92,336 71,236 169,617 151,446 
Other income (expense), net(2,334)276 (2,284)(151)
Loss on ECP Warrants(12,159)— (13,634)— 
Interest expense(15,502)(21,990)(29,455)(45,818)
Gain on early extinguishment of debt— 54,235 — 54,235 
Income (loss) before income taxes and
equity method investment income
(22,290)53,292 (15,631)53,730 
Income tax benefit248 389 262 402 
Income from equity method investees2,304 3,040 4,619 6,351 
Net income (loss)$(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.

29

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
Change
(Dollars in thousands)(Dollars in thousands)
Revenues:
Gathering services and related fees$11,349 $11,538 (2)%$19,920 $18,500 8%
Total revenues11,349 11,538 (2)%19,920 18,500 8%
Costs and expenses:
Operation and maintenance658 757 (13%)1,436 1,698 (15%)
General and administrative28 84 (67%)89 172 (48%)
Depreciation and amortization1,928 1,920 3,854 3,847 
Gain on asset sales, net— (42)*— (26)*
Total costs and expenses2,614 2,719 (4%)5,379 5,691 (5%)
Add:
Depreciation and amortization1,928 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.

30

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
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.

31

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,
20212020Percentage
Change
20212020Percentage
Change
Aggregate average daily throughput -
natural gas (MMcf/d)
1214(14%)1214(14%)
Aggregate average daily throughput -
liquids (Mbbl/d)
6376(17%)6487(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,
20212020Percentage
Change
20212020Percentage
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 sales8,201 3,131 162%20,428 7,455 174%
Other revenues4,242 2,776 53%8,749 5,918 48%
Total revenues24,959 18,314 36%54,326 49,577 10%
Costs and expenses:
Cost of natural gas and NGLs8,548 941 808%20,873 2,604 702%
Operation and maintenance5,483 5,827 (6%)10,407 12,549 (17%)
General and administrative332 492 (33%)686 1,030 (33%)
Depreciation and amortization5,915 6,487 (9%)11,837 12,982 (9%)
Gain on asset sales, net— (96)*(15)(47)*
Long-lived asset impairment41 *41 *
Total costs and expenses20,319 13,660 49%43,829 29,127 50%
Add:
Depreciation and amortization5,915 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 impairment41 41 
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.
32

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
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 sales305 71 330%415 141 194%
Other revenues1,856 993 87%2,560 2,027 26%
Total revenues8,052 6,292 28%15,129 14,251 6%
Costs and expenses:
Cost of natural gas and NGLs214 *230 11 *
Operation and maintenance1,882 2,354 (20%)3,794 4,870 (22%)
General and administrative1,350 141 857%1,669 223 648%
Depreciation and amortization1,544 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 expenses4,985 4,076 8,877 11,845 (25%)
Add:
Depreciation and amortization1,544 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.
33

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
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 sales6,875 4,222 63%13,393 8,734 53%
Other revenues121 126 (4%)237 313 (24%)
Total revenues9,258 7,059 31%18,091 14,069 29%
Costs and expenses:
Cost of natural gas and NGLs7,167 3,691 94%14,182 7,840 81%
Operation and maintenance1,527 1,456 5%2,519 2,643 (5%)
General and administrative118 84 40%235 177 33%
Depreciation and amortization1,464 1,387 6%2,933 2,732 7%
Gain on asset sales, net— (17)*— (13)*
Long-lived asset impairment— — — 182 *
Total costs and expenses10,276 6,601 56%19,869 13,561 47%
Add:
Depreciation and amortization1,464 1,387 2,933 2,732 
Gain on asset sales, net— (17)— (13)
Long-lived asset impairment— — — 182 
Other15 — 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.

34

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
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 revenues1,233 1,096 13%2,409 2,161 11%
Total revenues27,785 27,719 0%55,598 56,976 (2%)
Costs and expenses:
Cost of natural gas and NGLs697 320 118%1,816 777 134%
Operation and maintenance5,367 5,267 2%10,309 10,205 1%
General and administrative345 276 25%643 561 15%
Depreciation and amortization10,757 11,306 (5%)21,631 22,604 (4%)
(Gain) loss on asset sales, net(83)*(53)(96)*
Long-lived asset impairment— — *970 — *
Total costs and expenses17,170 17,086 0%35,316 34,051 4%
Add:
Depreciation and amortization10,757 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(83)(53)(96)
Long-lived asset impairment— — 970 — 
Other351 — 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.

35

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
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 sales10 2,858 (100%)66 6,729 (99%)
Other revenues (1)
1,012 1,778 (43%)2,072 3,038 (32%)
Total revenues11,098 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 maintenance1,852 4,564 (59%)4,316 9,259 (53%)
General and administrative260 513 (49%)495 891 (44%)
Depreciation and amortization3,798 3,788 7,596 7,585 
(Gain) loss on asset sales, net(11)(42)*(11)17 *
Long-lived asset impairment— — *289 *
Total costs and expenses5,899 9,957 (41%)12,685 20,837 (39%)
Add:
Depreciation and amortization4,032 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 
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.

36

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,
20212020Percentage
Change
20212020Percentage
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,
20212020Percentage
Change
20212020Percentage
Change
(Dollars in thousands)(Dollars in thousands)
Revenues:
Gathering services and related fees$6,612 $5,928 12%$12,813 $12,163 5%
Total revenues6,612 5,928 12%12,813 12,163 5%
Costs and expenses:
Operation and maintenance658 933 (29%)1,160 1,746 (34%)
General and administrative76 97 (22%)165 190 (13%)
Depreciation and amortization2,301 2,300 0%4,605 4,600 0%
(Gain) loss on asset sales, net— *(54)— *
Long-lived asset impairment(8)— *130 — *
Total costs and expenses3,035 3,330 (9%)6,006 6,536 (8%)
Add:
Depreciation and amortization2,301 2,300 4,605 4,600 
Adjustments related to capital
reimbursement activity
(10)(10)(19)(19)
(Gain) loss on asset sales, net— (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.
37


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,
20212020Percentage
Change
20212020Percentage
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 costs450 1,207 *217 1,218 *
Interest expense15,502 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,
38

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
39

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,
20212020
(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
SMLPObligor Group
(In thousands)
Assets
Current assets$3,156 $74,542 
Noncurrent assets5,561 2,207,593 
Liabilities
Current liabilities$26,491 $814,684 
Noncurrent liabilities35,537 538,339 
December 31, 2020
SMLPObligor Group
(In thousands)
Assets
Current assets$2,265 $78,304 
Noncurrent assets6,952 2,277,807 
Liabilities
Current liabilities$13,339 $50,192 
Noncurrent liabilities19,987 1,398,872 
Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities' results would have been had they operated on a stand-alone basis. Summarized statements of operations for the three months ended June 30, 2021 and for the year ended December 31, 2020 follow.
Six Months Ended June 30, 2021
SMLPObligor Group
(In thousands)
Total revenues$— $199,359 
Total costs and expenses20,669 149,152 
Income (loss) before income taxes and income from
equity method investees
(34,298)21,213 
Income from equity method investees$— $5,765 
Net income (loss)(34,036)26,978 
Year Ended December 31, 2020
SMLPObligor Group
(In thousands)
Total revenues$— $383,473 
Total costs and expenses26,169 302,989 
Income (loss) before income taxes and loss from
equity method investees
(26,000)122,108 
Income from equity method investees— 13,073 
Net income (loss)$(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 numberDescription
3.1
3.2
3.3
3.4
10.1+
10.2+
10.3+
22.1
31.1+
31.2+
32.1+
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)

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