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~~

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

For the quarterly period ended June 30, ~~2019~~2020

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

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

For the transition period from to

Commission file number: 001-35666

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

45-5200503

(I.R.S. Employer

Identification No.)

~~1790 Hughes Landing Blvd,~~910 Louisiana Street, Suite ~~500~~4200

~~The Woodlands,~~Houston, TX

(Address of principal executive offices)

~~77380~~77002

(Zip Code)

(832) 413-4770

(Registrant’s telephone number, including area code)

Not applicable

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

☒~~Yes~~☐No

Yes

☐

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

Large accelerated filer ☒☐		Accelerated filer ☐☒
Non-accelerated filer ☐		Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

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

Class		As of July 31, ~~2019~~2020
Common Units		~~82,704,891~~55,880,540 units

TABLE OF CONTENTS

COMMONLY USED OR DEFINED TERMS		2

PART I	FINANCIAL INFORMATION	45
Item 1.	Financial Statements.	45
	Unaudited Condensed Consolidated Balance Sheets as of June 30, ~~2019~~2020 and December 31, ~~2018~~2019	45
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, ~~2019~~2020 and ~~2018~~2019	56
	Unaudited Condensed Consolidated Statements of Partners' Capital for the three and six months ended June 30, ~~2019~~2020 and ~~2018~~2019	67
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, ~~2019~~2020 and ~~2018~~2019	79
	Notes to Unaudited Condensed Consolidated Financial Statements	911
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	3234
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	5361
Item 4.	Controls and Procedures.	5462

PART II	OTHER INFORMATION	5563
Item 1.	Legal Proceedings.	5563
Item 1A.	Risk Factors.	5563
Item 5.	Other Information	67
Item 6.	Exhibits.	5668

SIGNATURES		5770

COMMONLY USED OR DEFINED TERMS

2016 Drop Down	the Partnership's March 3, 2016 acquisition from SMP Holdings of substantially all of (i) the issued and outstanding membership interests in Summit Utica, Meadowlark Midstream and Tioga Midstream and (ii) SMP Holdings’ 40% ownership interest in Ohio Gathering
5.5% Senior Notes	Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
5.75% Senior Notes	Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025
associated natural gas	a form of natural gas which is found with deposits of petroleum, either dissolved in the crude oil or as a free gas cap above the crude oil in the reservoir
ASU	Accounting Standards Update
Bbl	one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons
Bcf	one billion cubic feet
Bison Midstream	Bison Midstream, LLC
Board of Directors	the board of directors of our General Partner
condensate	a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
Deferred Purchase Price Obligation	the deferred payment liability recognized in connection with the 2016 Drop ~~Down;~~Down, as ~~also referred to as DPPO~~subsequently amended
DFW Midstream	DFW Midstream Services LLC
DJ Basin	Denver-Julesburg Basin
Double E	Double E Pipeline, LLC
Double E Project	the development and construction of a long-haul natural gas pipeline with an initial throughput capacity of 1.35 billion cubic feet per day that will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas
dry gas	natural gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing or treating
Energy Capital Partners	Energy Capital Partners II, LLC and its parallel and co-investment ~~funds; also known~~ ~~as the Sponsor~~funds
Epping	Epping Transmission Company, LLC
EPU	earnings or loss per unit
~~Equity Restructuring~~	~~A series of transactions consummated on March 22, 2019, pursuant to which the~~ ~~Partnership cancelled its IDRs and converted its 2% economic GP interest~~ ~~to a non-economic GP interest in exchange for 8,750,000 SMLP common~~ ~~units, which were issued to SMP Holdings~~
FASB	Financial Accounting Standards Board
Finance Corp.	Summit Midstream Finance Corp.
GAAP	accounting principles generally accepted in the United States of America
General Partner	Summit Midstream GP, LLC
GP	general partner
~~General Partner~~Grand River	~~Summit Midstream GP,~~Grand River Gathering, LLC
Guarantor Subsidiaries	Bison Midstream and its subsidiaries, Grand River and its ~~subsidiary,~~subsidiaries, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, ~~Summit~~OpCo, ~~Niobrara, OpCo,~~ Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer ~~and Summit Permian Transmission~~
~~Grand River~~	~~Grand River Gathering, LLC~~
~~IDR~~	~~incentive distribution rights~~Midstream
LIBOR	London Interbank Offered Rate
Mbbl	one thousand barrels
Mbbl/d	one thousand barrels per day
Mcf	one thousand cubic feet
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Meadowlark Midstream	Meadowlark Midstream Company, LLC
MMcf	one million cubic feet
MMcf/d	one million cubic feet per day
Mountaineer Midstream	Mountaineer Midstream ~~gathering system~~Company, LLC
MVC	minimum volume commitment
NGLs	natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from unprocessed natural gas streams become liquid under various levels of higher pressure and lower temperature

Niobrara G&P	Niobrara Gathering and Processing system
OCC	Ohio Condensate Company, L.L.C.
OGC	Ohio Gathering Company, L.L.C.
Ohio Gathering	Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C.
OpCo	Summit Midstream OpCo, LP
Operator	Summit Operating Services Company, LLC
play	a proven geological formation that contains commercial amounts of hydrocarbons
Permian Finance	Summit Midstream Permian Finance, LLC
Permian Holdco	Summit Permian Transmission Holdco, LLC
Polar and Divide	the Polar and Divide system; collectively Polar Midstream and Epping
Polar Midstream	Polar Midstream, LLC
produced water	water from underground geologic formations that is a by-product of natural gas and crude oil production
~~Project~~	~~In June 2019, we announced a final investment decision to proceed with 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~~
Red Rock Gathering	Red Rock Gathering Company, LLC
~~Remaining Consideration~~	~~the consideration to be paid to SMP Holdings in 2020 in connection with the 2016~~ ~~Drop Down, the present value of which is reflected on our balance sheets as the~~ ~~Deferred Purchase Price Obligation~~
Revolving Credit Facility	the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 2017, ~~and by~~ the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 and the Third Amendment to Third Amended and Restated Credit Agreement dated as of December 24, 2019
SEC	Securities and Exchange Commission
segment adjusted EBITDA	total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit- based and noncash compensation, (vii) ~~the change in the Deferred Purchase~~ ~~Price Obligation fair value, (viii)~~ impairments and ~~(ix)~~(viii) other noncash expenses or losses, less other noncash income or gains
Senior Notes	The 5.5% Senior Notes and the 5.75% Senior Notes, collectively
Series A Preferred Units	Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
shortfall payment	the payment received from a counterparty when its volume throughput does not meet its MVC for the applicable period
SMLP	Summit Midstream Partners, LP
SMLP Holdings	SMLP Holdings, LLC
SMLP LTIP	SMLP Long-Term Incentive Plan
SMP Holdings	Summit Midstream Partners Holdings, LLC
~~Sponsor~~SMPH Term Loan	~~Energy Capital Partners II, LLC and its parallel and co-investment funds; also known~~the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings, as ~~Energy Capital Partners~~borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent
Subsidiary Series A Preferred Units	Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco
Summit Holdings	Summit Midstream Holdings, LLC
Summit Investments	Summit Midstream Partners, LLC
Summit Marketing	Summit Midstream Marketing, LLC
Summit Niobrara	Summit Midstream Niobrara, LLC
Summit Permian	Summit Midstream Permian, LLC
Summit Permian II	Summit Midstream Permian II, LLC
Summit Permian Transmission	Summit Permian Transmission, LLC
Summit Utica	Summit Midstream Utica, LLC
the Company	Summit Midstream Partners, LLC and its subsidiaries
the Partnership	Summit Midstream Partners, LP and its subsidiaries
the Partnership Agreement	the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
throughput volume	the volume of natural gas, crude oil or produced water gathered, transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput
Tioga Midstream	Tioga Midstream, LLC

unconventional resource

basin

a basin where natural gas or crude oil production is developed from unconventional

sources that require hydraulic fracturing as part of the completion process, for

instance, natural gas produced from shale formations and coalbeds; also

referred to as an unconventional resource play

wellhead

the equipment at the surface of a well, used to control the well's pressure; also, the

point at which the hydrocarbons and water exit the ground

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,		June 30,		December 31,
	2019		2018		2020		2019
	(In thousands, except unit amounts)				(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	535	$	4,345	$	36,571	$	9,530
Restricted cash						5,048		27,392
Accounts receivable		84,125		97,936		77,199		97,418
Other current assets		2,011		3,971		4,252		5,521
Total current assets		86,671		106,252		123,070		139,861
Property, plant and equipment, net		1,878,851		1,963,713		1,855,889		1,882,489
Intangible assets, net		251,250		273,416		215,901		232,278
Goodwill		16,211		16,211
Investment in equity method investees		653,807		649,250		383,058		309,728
Other noncurrent assets		10,912		11,720		8,584		9,742
Total assets	$	2,897,702	$	3,020,562	$	2,586,502	$	2,574,098

Liabilities and Partners' Capital
Liabilities and Capital
Current liabilities:
Trade accounts payable	$	25,252	$	38,414	$	18,422	$	24,415
Accrued expenses		8,759		21,963		11,331		11,339
Due to affiliate		387		240
Deferred revenue		12,325		11,467		15,354		13,493
Ad valorem taxes payable		6,737		10,550		6,307		8,477
Accrued interest		12,381		12,286		11,737		12,346
Accrued environmental remediation		2,561		2,487		1,795		1,725
Other current liabilities		11,949		12,645		9,859		12,206
Deferred Purchase Price Obligation		292,073		—
Short-term debt and current portion of long-term debt						38,000		5,546
Total current liabilities		372,424		110,052		112,805		89,547
Long-term debt		1,365,564		1,257,731		1,545,133		1,622,279
Noncurrent Deferred Purchase Price Obligation		—		383,934
Noncurrent deferred revenue		40,201		39,504		42,348		38,709
Noncurrent accrued environmental remediation		2,841		3,149		2,311		2,926
Other noncurrent liabilities		9,557		4,968		8,618		7,951
Total liabilities		1,790,587		1,799,338		1,711,215		1,761,412
Commitments and contingencies (Note 16)
Commitments and contingencies (Note 15)

Series A Preferred Units (300,000 units issued and outstanding at June 30, 2019 and December 31, 2018)		293,616		293,616
Common limited partner capital (82,704,891 units issued and outstanding at June 30, 2019 and 73,390,853 units issued and outstanding at December 31, 2018)		813,499		902,358
General Partner interests (zero units issued and outstanding at June 30, 2019 and 1,490,999 units issued and outstanding at December 31, 2018)		—		25,250
Mezzanine Capital
Subsidiary Series A Preferred Units (82,400 units issued and outstanding at June 30, 2020 and 30,058 units issued and outstanding at December 31, 2019)						78,563		27,450

Partners' Capital
Series A Preferred Units (300,000 units issued and outstanding at June 30, 2020 and December 31, 2019)						307,866		293,616
Common limited partner capital (43,543,056 units issued and outstanding at June 30, 2020 and 45,318,866 units issued and outstanding at December 31, 2019)						488,858		305,550
Noncontrolling interest						—		186,070
Total partners' capital		1,107,115		1,221,224		796,724		785,236
Total liabilities and partners' capital	$	2,897,702	$	3,020,562
Total liabilities, mezzanine capital and partners' capital					$	2,586,502	$	2,574,098

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018			2020			2019			2020			2019
	(In thousands, except per-unit amounts)												(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	75,107		$	89,585		$	162,071		$	173,946		$	73,911		$	75,107		$	157,703		$	162,071
Natural gas, NGLs and condensate sales		18,291			31,891			56,219			58,008			10,683			18,291			24,463			56,219
Other revenues		6,288			6,707			12,804			13,549			7,413			6,288			14,744			12,804
Total revenues		99,686			128,183			231,094			245,503			92,007			99,686			196,910			231,094
Costs and expenses:
Cost of natural gas and NGLs		11,571			24,384			43,330			44,670			6,088			11,571			14,313			43,330
Operation and maintenance		23,718			24,466			47,940			49,070			21,152			24,318			42,963			48,540
General and administrative		10,214			13,484			27,495			27,926			12,786			10,565			29,347			28,950
Depreciation and amortization		26,800			26,784			54,527			53,461			29,630			26,837			59,296			54,601
Transaction costs		—			—			950			—			1,207			96			1,218			2,433
(Gain) loss on asset sales, net		(287	)		62			(1,248	)		(12	)
Gain on asset sales, net														(281	)		(287	)		(166	)		(1,248	)
Long-lived asset impairment		70			587			45,021			587			654			70			4,475			45,021
Total costs and expenses		72,086			89,767			218,015			175,702			71,236			73,170			151,446			221,627
Other income		83			27			292			20
Other income (expense)														276			83			(151	)		292
Interest expense		(17,941	)		(14,837	)		(35,468	)		(29,959	)		(21,990	)		(22,343	)		(45,818	)		(45,085	)
Deferred Purchase Price Obligation		(3,712	)		(69,305	)		(8,139	)		(90,963	)
Income (loss) before income taxes and loss from equity method investees		6,030			(45,699	)		(30,236	)		(51,101	)
Income tax expense		(1,142	)		(294	)		(1,349	)		(123	)
Loss from equity method investees		(79	)		(3,920	)		(520	)		(2,534	)
Gain on early extinguishment of debt														54,235			—			54,235			—
Income (loss) before income taxes and income (loss) from equity method investees														53,292			4,256			53,730			(35,326	)
Income tax benefit (expense)														389			(1,149	)		402			(1,406	)
Income (loss) from equity method investees														3,040			(79	)		6,351			(520	)
Net income (loss)	$	4,809		$	(49,913	)	$	(32,105	)	$	(53,758	)	$	56,721		$	3,028		$	60,483		$	(37,252	)
Less:
Net income attributable to noncontrolling interest		—			58			—			143
Net income (loss) attributable to SMLP		4,809			(49,971	)		(32,105	)		(53,901	)
Net income attributable to General Partner, including IDRs		—			1,140			12			3,198
Net income (loss) attributable to noncontrolling interest														(1,393	)		(1,341	)		(3,274	)		(26,911	)
Net income (loss) attributable to limited partners		4,809			(51,111	)		(32,117	)		(57,099	)		58,114			4,369			63,757			(10,341	)
Net income attributable to Series A Preferred Units		7,125			7,125			14,250			14,250			7,125			7,125			14,250			14,250
Net loss attributable to common limited partners	$	(2,316	)	$	(58,236	)	$	(46,367	)	$	(71,349	)
Net income attributable to Subsidiary Series A Preferred Units														1,397			—			2,342			—
Net income (loss) attributable to common limited partners													$	49,592		$	(2,756	)	$	47,165		$	(24,591	)

Loss per limited partner unit:
Income (Loss) per limited partner unit:
Common unit – basic	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)	$	1.11		$	(0.06	)	$	1.05		$	(0.54	)
Common unit – diluted	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)	$	1.06		$	(0.06	)	$	1.02		$	(0.54	)

Weighted-average limited partner units outstanding:
Common units – basic		82,700			73,356			79,266			73,245			44,650			45,319			44,985			45,319
Common units – diluted		82,700			73,356			79,266			73,245			46,737			45,319			46,323			45,319

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

Partners' capital

Limited partners

Series A Preferred Units

Common

General Partner

Total

(In thousands)

Partners' capital, January 1, 2019

$
293,616

$
902,358

$
25,250

$
1,221,224

Net income (loss)

7,125

(44,051
)

12

(36,914
)
Conversion of General Partner economic
    interests

—

22,222

(22,222
)

—

Distributions to unitholders

—

(42,241
)

(3,040
)

(45,281
)
Unit-based compensation

—

2,526

—

2,526

Tax withholdings on vested SMLP LTIP
    awards

—

(2,522
)

—

(2,522
)
Partners' capital, March 31, 2019

300,741

838,292

—

1,139,033

Net income (loss)

7,125

(2,316
)

—

4,809

Distributions to unitholders

(14,250
)

(23,775
)

—

(38,025
)
Unit-based compensation

—

1,393

—

1,393

Tax withholdings on vested SMLP LTIP
    awards

—

(95
)

—

(95
)
Partners' capital, June 30, 2019

$
293,616

$
813,499

$
—

$
1,107,115

Partners' capital

Limited partners

Series A Preferred Units

Common

General Partner

Noncontrolling interest

Total

(In thousands)

Partners' capital, December 31, 2017,
    as reported

$
294,426

$
1,056,510

$
27,920

$
10,813

$
1,389,669

January 1, 2018 impact of Topic 606
    day 1 adoption

—

4,130

84

—

4,214

Partners' capital, January 1, 2018

294,426

1,060,640

28,004

10,813

1,393,883

Net income (loss)

7,125

(13,113
)

2,058

85

(3,845
)
Distributions to unitholders

—

(42,024
)

(3,029
)

—

(45,053
)
Unit-based compensation

—

1,979

—

—

1,979

Tax withholdings on vested SMLP LTIP
    awards

—

(1,943
)

—

—

(1,943
)
Other

(810
)

(130
)

—

—

(940
)
Partners' capital, March 31, 2018

300,741

1,005,409

27,033

10,898

1,344,081

Net income (loss)

7,125

(58,236
)

1,140

58

(49,913
)
Distributions to unitholders

(14,250
)

(42,180
)

(3,036
)

—

��

(59,466
)
Unit-based compensation

—

2,004

—

—

2,004

Tax withholdings on vested SMLP LTIP
    awards

—

103

—

—

103

Other

—

(1
)

—

—

(1
)
Partners' capital, June 30, 2018

$
293,616

$
907,099

$
25,137

$
10,956

$
1,236,808


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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)


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

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six months ended June 30,						Six months ended June 30,
	2019			2018			2020			2019
	(In thousands)						(In thousands)
Cash flows from operating activities:
Net loss	$	(32,105	)	$	(53,758	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net income (loss)							$	60,483		$	(37,252	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		55,279			53,160			59,766			55,353
Noncash lease expense		1,530			—			1,557			1,530
Amortization of debt issuance costs		2,175			2,086			3,136			3,121
Deferred Purchase Price Obligation		8,139			90,963
Unit-based and noncash compensation		4,079			4,223			4,569			4,079
Loss from equity method investees		520			2,534
(Income) loss from equity method investees								(6,351	)		520
Distributions from equity method investees		18,217			17,124			12,749			18,217
Gain on asset sales, net		(1,248	)		(12	)
Loss (gain) on asset sales, net								(166	)		(1,248	)
Gain on early extinguishment of debt								(54,235	)		—
Long-lived asset impairment		45,021			587			4,475			45,021
Changes in operating assets and liabilities:
Accounts receivable		13,237			(6,265	)		20,219			13,237
Trade accounts payable		(1,463	)		(3,483	)		1,411			(1,464	)
Accrued expenses		(12,537	)		6,934			(8	)		(11,768	)
Due from (to) affiliate		147			(997	)
Deferred revenue, net		2,007			3,281			5,500			2,007
Ad valorem taxes payable		(3,265	)		(1,825	)		(2,170	)		(3,265	)
Accrued interest		95			(51	)		(609	)		124
Accrued environmental remediation, net		(1,001	)		(1,805	)		(545	)		(1,001	)
Other, net		(2,581	)		(2,647	)		(4,410	)		(2,637	)
Net cash provided by operating activities		96,246			110,049			105,371			84,574
Cash flows from investing activities:
Capital expenditures		(111,092	)		(90,394	)		(27,426	)		(111,092	)
Proceeds from asset sale (net of cash of $1,475 for the six months ended June 30, 2019)		89,761			496
Proceeds from asset sale (net of cash of $1,475 for the period ended June 30, 2019)								—			89,761
Distribution from equity method investment		7,252			—			—			7,252
Investment in equity method investee		(5,921	)		—			(79,728	)		(5,921	)
Other, net		(160	)		(306	)		217			(160	)
Net cash used in investing activities		(20,160	)		(90,204	)		(106,937	)		(20,160	)

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Six months ended June 30,						Six months ended June 30,
	2019			2018			2020			2019
	(In thousands)						(In thousands)
Cash flows from financing activities:
Distributions to unitholders		(69,056	)		(90,269	)
Net cash distributions to noncontrolling interest SMLP unitholders								(6,037	)		(41,200	)
Distributions to Series A Preferred unitholders		(14,250	)		(14,250	)		—			(14,250	)
Net cash distributions to Energy Capital Partners								—			(68,984	)
Borrowings under Revolving Credit Facility		233,000			148,000			90,000			233,000
Repayments under Revolving Credit Facility		(126,000	)		(53,000	)
Repayment of Deferred Purchase Price Obligation		(100,000	)		—
Repayments on Revolving Credit Facility								(34,000	)		(126,000	)
Repayments on SMP Holdings term loan								(6,300	)		(53,750	)
Repurchase of Senior Notes								(76,707	)		—
Proceeds from issuance of Series A preferred units, net of costs								48,710			—
Borrowings under ECP Loans								35,000			—
Purchase of common units in GP Buy-In Transaction								(41,778	)		—
Debt issuance costs		(56	)		(121	)		(1,080	)		(229	)
Proceeds from asset sale								288			—
Other, net		(3,534	)		(3,423	)		(1,833	)		(3,532	)
Net cash used in financing activities		(79,896	)		(13,063	)
Net change in cash and cash equivalents		(3,810	)		6,782
Cash and cash equivalents, beginning of period		4,345			1,430
Cash and cash equivalents, end of period	$	535		$	8,212
Net cash provided by (used in) financing activities								6,263			(74,945	)
Net change in cash, cash equivalents and restricted cash								4,697			(10,531	)
Cash, cash equivalents and restricted cash, beginning of period								36,922			16,173
Cash, cash equivalents and restricted cash, end of period (1)							$	41,619		$	5,642

Supplemental cash flow disclosures:
Cash interest paid	$	37,506		$	30,962		$	44,073		$	43,683
Less capitalized interest		4,361			3,085			819			4,361
Interest paid (net of capitalized interest)	$	33,145		$	27,877		$	43,254		$	39,322

Cash paid for taxes	$	150		$	175		$	—		$	150

Noncash investing and financing activities
Capital expenditures in trade accounts payable (period-end accruals)	$	22,051		$	20,598		$	12,442		$	22,051
Warrant issuance for GP Buy-In Transaction								2,300			—
Asset contribution to an equity method investment		23,643			—			—			23,643
Capital expenditures relating to contributions in aid of construction for Topic 606 day 1 adoption		—			33,123
Right-of-use assets relating to Topic 842		5,448			—
Right-of-use assets relating to ASC Topic 842								—			5,448
(1) A reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets follow:
							Six months ended June 30,
							2020			2019
							(In thousands)
Cash and cash equivalents							$	36,571		$	5,642
Restricted cash								5,048			—
Total cash, cash equivalents and restricted cash							$	41,619		$	5,642

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. SMLP, a Delaware limited partnership, was formed in May 2012 and began operations in October 2012. SMLP is a ~~growth-oriented~~value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in ~~the core producing areas of~~ unconventional resource basins, primarily shale formations, in the continental United States. Our business activities are conducted through various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

~~The General Partner,~~On May 3, 2020, the Partnership entered into a Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company ~~manages our operations and activities.~~(“ECP”). On May 28, 2020 (the “Closing Date”), the transactions contemplated by the Purchase Agreement closed.

Pursuant to the Purchase Agreement, the Partnership acquired (i) all the outstanding limited liability company interests of Summit ~~Investments,~~Midstream Partners, LLC, a Delaware limited liability company (“Summit Investments”), which is the ~~ultimate owner~~sole member of ~~our General Partner~~Summit Midstream Partners Holdings, LLC, a Delaware limited liability company (“SMP Holdings”), which in turn owns (a) 34,604,581 common units representing limited partner interests in the Partnership (the “common units”) pledged as collateral under the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings, as borrower, the lenders party thereto and ~~has~~Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent (the “SMPH Term Loan”), (b) 10,714,285 common units not pledged as collateral under the SMPH Term Loan and (c) the right of SMP Holdings to ~~appoint~~receive the ~~entire Board~~deferred purchase price obligation under the Contribution Agreement by and between the Partnership and SMP Holdings, dated February 25, 2016, as amended (the “Contribution Agreement”), and (ii) 5,915,827 common units held by SMLP Holdings, LLC, a Delaware limited liability company and an affiliate of ~~Directors.~~ECP (“ECP Holdings”). The total purchase price under the Purchase Agreement was $35 million in cash and warrants to purchase up to 10 million common units (Refer to Note 11 for additional details). Pursuant to the Purchase Agreement, SMP Holdings continues to retain the liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream Company, LLC that occurred near Williston, North Dakota and was discovered on January 6, 2015. We refer to the transactions contemplated by the Purchase Agreement as the “GP Buy-In Transaction.”

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

Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is ~~controlled by Energy Capital Partners.~~

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 ~~owned an approximate~~2%~~general partner interest in~~controlled SMLP ~~(including the IDRs) until March 22, 2019. On March 22, 2019, we executed an equity restructuring agreement with the General Partner~~ and ~~SMP Holdings pursuant to which the IDRs and the 2% general partner interest~~SMLP’s financial statements were ~~converted~~consolidated into a non-economic general partner interest in exchange for 8,750,000 common units which were issued to SMP Holdings (the “Equity Restructuring”). As of June 30, 2019, SMP Holdings, a wholly owned subsidiary of Summit ~~Investments, beneficially owned34,604,581SMLP common unitsand a subsidiary of Energy Capital Partners directly owned 5,915,827 SMLP common units.~~

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

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota. Refer to Note 17 for details on the sale of Tioga Midstream.

In June 2019, in conjunction with the Project, Summit Permian Transmission entered into a definitive joint venture agreement (the “Agreement”) with an affiliate of Double E’s foundation shipper (the “JV Partner”) to fund the capital expenditures associated with the Project. Refer to Note 8 for additional details.

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

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

~~These unaudited condensed~~The accompanying consolidated financial statements ~~have been~~were prepared ~~pursuant to~~using GAAP for interim financial information and in accordance with the rules and ~~the~~ regulations of the ~~SEC. Certain~~Securities and Exchange Commission. As permitted under those rules, certain information relating to the Company’s organization and ~~note~~footnote disclosures normally included in ~~the annual~~ financial statements prepared in accordance with GAAP have been appropriately condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments which are necessary to fairly present the unaudited condensed consolidated balance sheet as of June 30, 2019, the unaudited condensed consolidated statements of operations and statements of partners’ capital for the three and six months ended June 30, 2019 and 2018 and the unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2019 and 2018. The balance sheet at December 31, 2018 included herein was derived from our audited financial statements, but does not include all disclosures required by GAAP. See Note 2 for the impact relating to the adoption of the new lease standard. These unaudited condensedomitted. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto ~~that are~~ included in ~~our annual report~~the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2018, as filed with the SEC on February 26,~~ 2019 ~~(the "2018~~(“2019 Annual ~~Report"~~Report”). The Partnership believes the disclosures made are adequate to make the information presented not misleading.

The 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 anthe interim periods presented herein.

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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Except for the changes below, there have been no changes to our significant accounting policies since December 31, ~~2018.~~2019.

Cash, Cash Equivalents and Restricted Cash. We consider 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 us is classified as restricted cash. The restricted cash balance of $5.0 million at June 30, 2020 is primarily associated with an ongoing customer dispute and became unrestricted in July 2020, when an agreement was reached in the dispute. In conjunction with that agreement, the parties have agreed to (1) request dismissal of relevant lawsuits and modify the relevant gathering agreement, (2) petition the court to release to DFW Midstream approximately $5.4 million held in the court’s registry, and (3) the customer’s payment of approximately $1.9 million to DFW Midstream in installment payments over the course of four months, beginning on September 1, 2020. The restricted cash balance of $27.4 million at December 31, 2019 is primarily related to cash amounts reserved for funding the construction of our Double E pipeline. See Note 12 for additional information.

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

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

•

ASU No. 2016-02 Leases (“Topic 842"). We adopted Topic 842 with a date of initial application of January 1, 2019. We applied Topic 842 by recognizing (i) a $5.4 million right-of-use (“ROU”) asset which represents the right to use, or to control the use of, specified assets for a lease term. The ROU asset is included in the Property, plant and equipment, net caption on the unaudited condensed consolidated balance sheet; and (ii) a $5.4 million lease liability for the obligation to make lease payments arising from the leases. The lease liability is included in the Other current liabilities and Other noncurrent liabilities captions on the unaudited condensed consolidated balance sheet. The comparative information has not been adjusted and is reported under the accounting standards in effect for those periods.

~~Refer to Note 16 for additional information.~~

~~Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncement as of June 30, 2019:~~

•

ASU No. 2018-13 Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU 2018-13 removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on our unaudited condensed consolidated financial statement disclosures.

•

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

Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncement as of June 30, 2020:

•

ASU No. 2020-04 Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU 2020-04 are effective as of March 12, 2020 through December 31, 2022. We are currently evaluating the provisions of ASU ~~2018-13~~2020-04 to determine its impact on our unaudited condensed consolidated financial statements and ~~related disclosures and will adopt its provisions effective January 1, 2020.~~disclosures.

3. REVENUE

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

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

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

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

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

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

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

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

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

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

The following table presents estimated revenue expected to be recognized during the remainder of ~~2019~~2020 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.

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

2019

2020

2021

2022

2023

Thereafter

(In thousands)

Gathering services and related fees

$
60,217

$
120,941

$
100,117

$
83,673

$
70,971

$
114,043

	2020		2021		2022		2023		2024		Thereafter
	(In thousands)
Gathering services and related fees	$	58,427	$	102,127	$	84,736	$	66,693	$	50,608	$	57,721

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

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

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

	Reportable Segments
	Three months ended June 30, 2019
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	7,591	$	15,685	$	4,021	$	586	$	30,555	$	11,428	$	5,897	$	75,763	$	(656	)	$	75,107
Natural gas, NGLs and condensate sales		—		3,768		101		2,406		2,104		6,273		—		14,652		3,639			18,291
Other revenues		—		2,670		1,034		49		945		1,646		—		6,344		(56	)		6,288
Total	$	7,591	$	22,123	$	5,156	$	3,041	$	33,604	$	19,347	$	5,897	$	96,759	$	2,927		$	99,686

	Reportable Segments
	Six months ended June 30, 2019
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	15,086	$	41,391	$	7,745	$	952	$	62,395	$	24,453	$	12,094	$	164,116	$	(2,045	)	$	162,071
Natural gas, NGLs and condensate sales		—		9,353		186		6,627		4,406		6,877		—		27,449		28,770			56,219
Other revenues		—		5,578		2,041		81		2,083		3,302		—		13,085		(281	)		12,804
Total	$	15,086	$	56,322	$	9,972	$	7,660	$	68,884	$	34,632	$	12,094	$	204,650	$	26,444		$	231,094

Reportable Segments

Three months ended June 30, 2018

Utica Shale

Williston Basin

DJ Basin

Piceance Basin

Barnett Shale

Marcellus Shale

Total reportable segments

All other segments

Total

(In thousands)

Major products /
    services lines

Gathering services
    and related fees

$
10,422

$
23,106

$
2,509

$
33,661

$
14,080

$
8,050

$
91,828

$
(2,243
)

$
89,585

Natural gas, NGLs
    and condensate
    sales

—

7,350

79

4,596

381

—

12,406

19,485

31,891

Other revenues

—

2,960

969

1,178

1,694

—

6,801

(94
)

6,707

Total

$
10,422

$
33,416

$
3,557

$
39,435

$
16,155

$
8,050

$
111,035

$
17,148

$
128,183

Reportable Segments

Six months ended June 30, 2018

Utica Shale

Williston Basin

DJ Basin

Piceance Basin

Barnett Shale

Marcellus Shale

Total reportable segments

All other segments

Total

(In thousands)

Major products /
    services lines

Gathering services
    and related fees

$
20,463

$
40,772

$
4,688

$
66,776

$
27,717

$
15,875

$
176,291

$
(2,345
)

$
173,946

Natural gas, NGLs
    and condensate
    sales

—

15,196

159

8,841

926

—

25,122

32,886

58,008

Other revenues

—

5,872

1,726

2,389

3,682

—

13,669

(120
)

13,549

Total

$
20,463

$
61,840

$
6,573

$
78,006

$
32,325

$
15,875

$
215,082

$
30,421

$
245,503

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

	June 30, 2019			December 31, 2018			June 30, 2020			December 31, 2019
	(In thousands)						(In thousands)
Contract assets, beginning of period	$	8,755		$	—		$	3,902		$	8,755
Additions		14,602			26,403			15,074			18,077
Transfers out		(5,550	)		(17,648	)		(1,876	)		(22,930	)
Contract assets, end of period	$	17,807		$	8,755		$	17,100		$	3,902

As of June 30, ~~2019,~~2020, receivables with customers totaled ~~$59.0~~$56.5 million and contract assets totaled ~~$17.8~~$17.1 million which were included in the Accounts receivable caption on the unaudited condensed consolidated balance sheet.

As of December 31, ~~2018,~~2019, receivables with customers totaled ~~$82.9~~$90.4 million and contract assets totaled ~~$8.8~~$3.9 million which were included in the Accounts receivable caption on the unaudited condensed consolidated balance sheet.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. We recognize contract liabilities under these arrangements in revenue over the contract period. For the three months ended June 30, ~~2019~~2020 and ~~2018,~~2019, we recognized ~~$2.7~~$2.3 million and ~~$3.9~~$2.7 million of gathering services and related fees which ~~was~~were included in the contract liability balance as of the beginning of the period. For the six months ended June 30, ~~2019~~2020 and ~~2018,~~2019, we recognized ~~$5.4~~$4.7 million and ~~$5.0~~$5.4 million of gathering services and related fees which ~~was~~were included in the contract liability balance as of the beginning of the period. See Note 98 for additional details.

4. SEGMENT INFORMATION

As of June 30, ~~2019,~~2020, our reportable segments are:

•

the Utica Shale, which is served by Summit Utica;

•

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

•

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

•

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

•

the Permian Basin, which is served by Summit Permian;

•

the Piceance Basin, which is served by Grand River;

•

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

•

the Marcellus Shale, which is served by Mountaineer Midstream.

~~Additionally, until~~Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston ~~Basin, which includes~~Basin. Until December 1, 2019, we owned certain assets in the ~~Bakken and Three Forks shale formations~~Red Rock Gathering system operating in ~~northwestern North Dakota.~~the Piceance Basin. Refer to Note 1716 to the unaudited condensed consolidated financial statements for details on the sale of Tioga ~~Midstream.~~Midstreamand on the sale of certain assets in the Red Rock Gathering system.

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

The Ohio Gathering reportable segment includes our investment in ~~OGC and OCC.~~Ohio Gathering. Income or loss from equity method investees, as reflected on the unaudited condensed consolidated statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag (see Note 8)7).

For the three and six months ended June 30, ~~2019,~~2020, other than the investment activity described in Note ~~8 below,~~7, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the third quarter of 2021.

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

Assets by reportable segment follow.

	June 30,2019		December 31, 2018			June 30, 2020		December 31, 2019
	(In thousands)					(In thousands)
Assets (1):
Utica Shale	$	206,911	$	207,357		$	210,592	$	206,368
Ohio Gathering		630,513		649,250			269,504		275,000
Williston Basin		439,026		526,819			453,327		452,152
DJ Basin		167,329		166,580			203,866		205,308
Permian Basin		174,964		145,702			169,710		185,708
Piceance Basin		672,664		699,638			605,786		631,140
Barnett Shale		358,997		376,564			357,824		350,638
Marcellus Shale		204,252		208,790			183,896		184,631
Total reportable segment assets		2,854,656		2,980,700			2,454,505		2,490,945
Corporate and Other		43,046		44,181			131,997		83,153
Eliminations		—		(4,319	)
Total assets	$	2,897,702	$	3,020,562		$	2,586,502	$	2,574,098

(1) At June 30, ~~2019,~~2020, Corporate and Other included ~~$23.3~~$113.6 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, ~~2018,~~2019, Corporate and Other included ~~$9.6~~$34.7 million ~~of capital expenditures~~ relating to our investment in Double E.

Revenues by reportable segment follow.

	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,					Six months ended June 30,
	2019			2018			2019			2018			2020		2019			2020		2019
	(In thousands)												(In thousands)
Revenues (1):
Utica Shale	$	7,591		$	10,422		$	15,086		$	20,463		$	11,538	$	7,591		$	18,500	$	15,086
Williston Basin		22,123			33,416			56,322			61,840			18,314		22,123			49,577		56,322
DJ Basin		5,156			3,557			9,972			6,573			6,292		5,156			14,251		9,972
Permian Basin		3,041			—			7,660			—			7,059		3,041			14,069		7,660
Piceance Basin		33,604			39,435			68,884			78,006			27,719		33,604			56,976		68,884
Barnett Shale		19,347			16,155			34,632			32,325			14,513		19,347			30,087		34,632
Marcellus Shale		5,897			8,050			12,094			15,875			5,928		5,897			12,163		12,094
Total reportable segments revenue		96,759			111,035			204,650			215,082			91,363		96,759			195,623		204,650
Corporate and Other		3,824			19,422			30,662			33,598			644		3,824			1,287		30,662
Eliminations		(897	)		(2,274	)		(4,218	)		(3,177	)		—		(897	)		—		(4,218	)
Total revenues	$	99,686		$	128,183		$	231,094		$	245,503		$	92,007	$	99,686		$	196,910	$	231,094

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

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

	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018			2020			2019			2020			2019
Percentage of total revenues (1):
Counterparty A - Piceance Basin		12	%		10	%		11	%		11	%		11	%		12	%		11	%		11	%
Counterparty B - Williston Basin		11	%	*				10	%	*			*				11	%	*				10	%
Counterparty C - Barnett Shale		14	%		11	%		12	%	*			*				14	%	*				12	%

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

* Less than 10%

Depreciation and amortization, including the amortization expense associated with our favorable ~~and unfavorable (for 2018)~~ gas gathering contracts as reported in ~~other~~Other revenues, by reportable segment follows.

	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018		2020		2019		2020		2019
	(In thousands)								(In thousands)
Depreciation and amortization (1):
Utica Shale	$	1,923	$	2,033	$	3,831	$	3,886	$	1,920	$	1,923	$	3,847	$	3,831
Williston Basin		4,734		5,622		10,170		11,231		6,487		4,734		12,982		10,170
DJ Basin		464		784		1,263		1,565		1,502		464		3,029		1,263
Permian Basin		1,163		—		2,235		—		1,387		1,163		2,732		2,235
Piceance Basin		11,810		11,666		23,601		23,440		11,306		11,810		22,604		23,601
Barnett Shale (2)		4,167		3,759		8,497		7,516		4,023		4,167		8,055		8,497
Marcellus Shale		2,286		2,274		4,569		4,546		2,300		2,286		4,600		4,569
Total reportable segment depreciation and amortization		26,547		26,138		54,166		52,184		28,925		26,547		57,849		54,166
Corporate and Other		616		496		1,113		976		941		653		1,917		1,187
Total depreciation and amortization	$	27,163	$	26,634	$	55,279	$	53,160	$	29,866	$	27,200	$	59,766	$	55,353

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

(2) Includes the amortization expense associated with our favorable ~~and unfavorable (for 2018)~~ gas gathering contracts as reported in ~~other~~Other revenues.

Cash paid for capital expenditures by reportable segment follow.

	Six months ended June 30,					Six months ended June 30,
	2019			2018		2020		2019
	(In thousands)					(In thousands)
Cash paid for capital expenditures (1):
Utica Shale	$	1,065		$	1,846	$	1,482	$	1,065
Williston Basin		14,230			10,966		7,423		14,230
DJ Basin		50,373			21,415		8,428		50,373
Permian Basin		28,163			50,773		4,921		28,163
Piceance Basin		1,497			3,412		404		1,497
Barnett Shale (2)		(37	)		349		869		(37	)
Marcellus Shale		108			545		430		108
Total reportable segment capital expenditures		95,399			89,306		23,957		95,399
Corporate and Other		15,693			1,088		3,469		15,693
Total cash paid for capital expenditures	$	111,092		$	90,394	$	27,426	$	111,092

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

(2) For the six months ended June 30, 2019, the amount includes sales tax reimbursements of $1.1 million.

During the six months ended June 30, 2019, Corporate and Other included cash paid of $0.3 million for corporate purposes; the remainder represents capital expenditures relating to the Double E Project.

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

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

Segment adjusted EBITDA by reportable segment follows.

	Three months ended June 30,					Six months ended June 30,
	2020		2019			2020		2019
	(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	10,693	$	6,640		$	16,621	$	12,833
Ohio Gathering		7,514		9,939			15,453		19,149
Williston Basin		12,727		16,650			28,919		35,384
DJ Basin		4,339		2,816			10,250		5,489
Permian Basin		1,828		(656	)		3,409		(1,206	)
Piceance Basin		21,734		24,584			45,291		50,583
Barnett Shale		8,510		11,208			17,270		22,582
Marcellus Shale		4,888		4,635			10,208		9,777
Total of reportable segments' measures of profit	$	72,233	$	75,816		$	147,421	$	154,591

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

(In thousands)

Reportable segment adjusted EBITDA

Utica Shale

$
6,640

$
9,223

$
12,833

$
17,938

Ohio Gathering

9,939

8,935

19,149

19,412

Williston Basin

16,650

19,030

35,384

35,000

DJ Basin

2,816

959

5,489

2,280

Permian Basin

(656
)

—

(1,206
)

—

Piceance Basin

24,584

26,714

50,583

54,628

Barnett Shale

11,208

11,093

22,582

20,952

Marcellus Shale

4,635

6,543

9,777

13,219

Total of reportable segments' measures of profit or loss

$
75,816

$
82,497

$
154,591

$
163,429

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

	Three months ended June 30,						Six months ended June 30,
	2020			2019			2020			2019
	(In thousands)
Reconciliation of income (loss) before income taxes and income (loss) from equity method investees to total of reportable segments' measures of profit:
Income (loss) before income taxes and income (loss) from equity method investees	$	53,292		$	4,256		$	53,730		$	(35,326	)
Add:
Corporate and Other expense		9,533			8,255			21,610			24,905
Interest expense		21,990			22,343			45,818			45,085
Gain on early extinguishment of debt		(54,235	)		—			(54,235	)		—
Depreciation and amortization		29,866			27,200			59,766			55,353
Proportional adjusted EBITDA for equity method investees		7,514			9,939			15,453			19,149
Adjustments related to MVC shortfall payments		2,291			3,533			(3,151	)		(666	)
Adjustments related to capital reimbursement activity		(237	)		(1,046	)		(448	)		(1,761	)
Unit-based and noncash compensation		1,846			1,553			4,569			4,079
Gain on asset sales, net		(281	)		(287	)		(166	)		(1,248	)
Long-lived asset impairment		654			70			4,475			45,021
Total of reportable segments' measures of profit	$	72,233		$	75,816		$	147,421		$	154,591

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

(In thousands)

Reconciliation of income (loss) before income taxes
    and loss from equity method investees to total
    of reportable segments' measures of profit:

Income (loss) before income taxes and loss
    from equity method investees

$
6,030

$
(45,699
)

$
(30,236
)

$
(51,101
)
Add:

Corporate and Other expense

7,208

9,002

21,367

19,625

Interest expense

17,941

14,837

35,468

29,959

Deferred Purchase Price Obligation

3,712

69,305

8,139

90,963

Depreciation and amortization

27,163

26,634

55,279

53,160

Proportional adjusted EBITDA for equity method
   investees

9,939

8,935

19,149

19,412

Adjustments related to MVC shortfall payments

3,533

(3,542
)

(666
)

(3,542
)
Adjustments related to capital reimbursement activity

(1,046
)

115

(1,761
)

155

Unit-based and noncash compensation

1,553

2,261

4,079

4,223

(Gain) loss on asset sales, net

(287
)

62

(1,248
)

(12
)
Long-lived asset impairment

70

587

45,021

587

Total of reportable segments' measures of profit

$
75,816

$
82,497

$
154,591

$
163,429

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

Adjustments related to MVC shortfall payments by reportable segment follow.

Three months ended June 30, 2019

Williston Basin

Piceance
Basin

Barnett
Shale

Total

(In thousands)

Adjustments related to expected MVC shortfall payments:

$
2,081

$
—

$
1,452

$
3,533

	Three months ended June 30, 2020
	Williston Basin		Piceance Basin		Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	2,124	$	167	$	—	$	2,291

Three months ended June 30, 2018

Williston Basin

Piceance
Basin

Barnett
Shale

Total

(In thousands)

Adjustments related to expected MVC shortfall payments:

$
(3,386
)

$
(93
)

$
(63
)

$
(3,542
)

	Three months ended June 30, 2019
	Williston Basin		Piceance Basin		Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	2,081	$	—	$	1,452	$	3,533

Six months ended June 30, 2019

Williston Basin

Piceance
Basin

Barnett
Shale

Total

(In thousands)

Adjustments related to expected MVC shortfall payments:

$
(3,468
)

$
(103
)

$
2,905

$
(666
)

	Six months ended June 30, 2020
	Williston Basin			Piceance Basin		Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(3,541	)	$	390	$	—	$	(3,151	)

Six months ended June 30, 2018

Williston Basin

Piceance
Basin

Barnett
Shale

Total

(In thousands)

Adjustments related to expected MVC shortfall payments:

$
(3,386
)

$
(93
)

$
(63
)

$
(3,542
)

	Six months ended June 30, 2019
	Williston Basin			Piceance Basin			Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(3,468	)	$	(103	)	$	2,905	$	(666	)

5. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	June 30, 2020		December 31, 2019
	(In thousands)
Gathering and processing systems and related equipment	$	2,193,200	$	2,182,950
Construction in progress		76,189		78,716
Land and line fill		10,440		10,137
Other		60,414		54,595
Total		2,340,243		2,326,398
Less accumulated depreciation		484,354		443,909
Property, plant and equipment, net	$	1,855,889	$	1,882,489

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

June 30, 2019

December 31, 2018

(In thousands)

Gathering and processing systems and related equipment

$
2,136,209

$
2,155,325

Construction in progress

76,086

137,920

Land and line fill

9,823

11,748

Other

61,045

45,853

Total

2,283,163

2,350,846

Less accumulated depreciation

404,312

387,133

Property, plant and equipment, net

$
1,878,851

$
1,963,713

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

In the ~~Barnett Shale, we determined, in the~~ first quarter of 2019, we determined that certain compressor station assets ~~would be shut down~~in the Barnett Shale were impaired and ~~decommissioned. As a result, we~~ recorded an impairment charge of $10.2 million, comprised of a $9.7 impairment of fixed assets and a $0.5 million ~~related to these assets in the first quarter~~impairment of ~~2019. See Note 6 for additional details.~~rights-of-way.

Depreciation expense and capitalized interest follow.

	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018		2020		2019		2020		2019
	(In thousands)								(In thousands)
Depreciation expense	$	18,829	$	18,657	$	38,612	$	37,214	$	21,664	$	18,866	$	43,362	$	38,686
Capitalized interest		2,446		1,863		4,361		3,085		328		2,446		819		4,361

6. AMORTIZING INTANGIBLE ASSETS

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

	June 30, 2019							June 30, 2020
	Gross carrying amount		Accumulated amortization			Net		Gross carrying amount		Accumulated amortization			Net
	(In thousands)							(In thousands)
Favorable gas gathering contracts	$	24,195	$	(14,657	)	$	9,538	$	24,195	$	(15,595	)	$	8,600
Contract intangibles		278,448		(156,755	)		121,693		278,448		(182,396	)		96,052
Rights-of-way		159,734		(39,715	)		120,019		157,202		(45,953	)		111,249
Total intangible assets	$	462,377	$	(211,127	)	$	251,250	$	459,845	$	(243,944	)	$	215,901

	December 31, 2018							December 31, 2019
	Gross carrying amount		Accumulated amortization			Net		Gross carrying amount		Accumulated amortization			Net
	(In thousands)							(In thousands)
Favorable gas gathering contracts	$	24,195	$	(13,905	)	$	10,290	$	24,195	$	(15,125	)	$	9,070
Contract intangibles		278,448		(143,962	)		134,486		278,448		(169,549	)		108,899
Rights-of-way		166,209		(37,569	)		128,640		157,175		(42,866	)		114,309
Total intangible assets	$	468,852	$	(195,436	)	$	273,416	$	459,818	$	(227,540	)	$	232,278

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

We recognized amortization expense in ~~other~~Other revenues as follows:

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

(In thousands)

Amortization expense – favorable gas gathering contracts

$
(363
)

$
(388
)

$
(752
)

$
(777
)

	Three months ended June 30,						Six months ended June 30,
	2020			2019			2020			2019
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(236	)	$	(363	)	$	(470	)	$	(752	)

We recognized amortization expense in costs and expenses as follows:

	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018		2020		2019		2020		2019
	(In thousands)								(In thousands)
Amortization expense – contract intangibles	$	6,397	$	6,535	$	12,794	$	13,070	$	6,423	$	6,397	$	12,847	$	12,794
Amortization expense – rights-of-way		1,574		1,592		3,121		3,177		1,543		1,574		3,087		3,121

The estimated aggregate annual amortization expected to be recognized for the remainder of ~~2019~~2020 and each of the four succeeding fiscal years follows.

	Intangible assets		Intangible assets
	(In thousands)		(In thousands)
2019	$	15,971
2020		32,049	$	15,951
2021		28,357		28,209
2022		25,290		25,142
2023		25,236		25,088
2024				14,917

7. ~~GOODWILL~~

We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. There have been no impairments of goodwill during the three and six months ended June 30, 2019.

~~Fair Value Measurement.~~Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments, as discussed in the 2018 Annual Report. Differing assumptions regarding any of these inputs could have a significant effect on the valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

8. EQUITY METHOD INVESTMENTS

Double E

In June 2019, we formed Double E in connection with the Double E Project. Effective June 26, 2019, Summit Permian Transmission, a wholly owned and consolidated subsidiary of the Partnership, and ~~our JV Partner~~ an affiliate of Double E’s foundation shipper (the “JV Partner”) executed ~~the Agreement~~an agreement whereby Double E will provide natural gas transportation services from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in ~~Texas.~~Texas (the “Double E Agreement”). Concurrent with the Double E Agreement, we issued a parental guaranty to fund any capital calls not satisfied by Summit Permian Transmission during the construction of the Double E Project, for an amount not to exceed $350.0 million. The Partnership has guaranteed, among other things, payment of our pro rata share of the required capital calls during construction of the Double E Project and, as of June 30, 2020, we estimate that our pro rata share of our remaining capital contributions is approximately $229 million, before the realization of any project cost efficiencies. In connection with the Double E Agreement and the related Double E Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and our JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Double E Agreement, Double E distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, we ~~also~~ made additional cash investments of ~~$5.9~~$18.3 million ~~during~~through December 31, 2019.

During the six months ended June ~~2019.~~30, 2020, we made cash investments of $79.7 million in the Double E Project.We are leading the development, permitting and construction of the Double E Project and expect to operate the pipeline upon commissioning.

Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Double E Agreement, Summit Permian Transmission iswas not deemed to be the primary beneficiary due to the JV Partner’s voting rights on significant matters. We account for our ownership interest in Double E as an equity method investment because we have significant influence over Double E. Our portion of Double E’s net assets, which was ~~$23.3~~$113.6 million at June 30, ~~2019,~~2020, is reported under the caption Investment in equity method investees on the unaudited condensed consolidated balance sheet.

For the three and six months ended June 30, ~~2019,~~2020, other than the investment activity noted above, Double E did ~~not~~0t have any results of operations given that the Double E Project is currently under development.

Ohio Gathering

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

As ~~a result~~ of ~~our joint venture partner funding a disproportionate amount of the capital calls during the six months ended~~ June 30, 2020 and December 31, 2019, our ownership interest in Ohio Gathering ~~decreased from 40.0% at December 31, 2018, to 39.0%~~was 38.3% and 38.5%, respectively, and provided below is a reconciliation of the difference at June 30, ~~2019.~~

~~A reconciliation of~~2020 between the amount at which our~~39.0%~~ownership interest in Ohio Gathering is carried to the amount of our underlying investment per Ohio Gathering's books and records ~~follows~~ (in thousands).

Investment in Ohio Gathering, June 30, 2020	$	269,504
June cash distributions		2,403
Basis difference		220,922
Investment in Ohio Gathering (Books and records), May 31, 2020	$	492,829

As noted in our 2019 Annual Report, in December 2019 an impairment loss of long-lived assets was recognized by OCC which brought our investment in OCC to 0. As a result, we have 0t recorded our portion of OCC’s net loss for the three and six months ended June 30, 2020 in the Income (loss) from equity method investees caption of our unaudited condensed consolidated statements of operations.

Investment in Ohio Gathering, June 30, 2019

$
630,513

June cash distributions

3,273

Basis difference

(110,156
)
Investment in Ohio Gathering, net of basis difference,
May 31, 2019

$
523,630

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

	Three months ended May 31, 2020				Three months ended May 31, 2019
	OGC		OCC		OGC		OCC
	(In thousands)
Total revenues	$	27,334	$	2,404	$	35,262	$	2,073
Total operating expenses		24,045		2,069		26,336		2,691
Net income (loss)		3,289		335		8,926		(619	)

	Three months ended May 31, 2019					Three months ended May 31, 2018						Six months ended May 31, 2020					Six months ended May 31, 2019
	OGC		OCC			OGC			OCC			OGC		OCC			OGC		OCC
	(In thousands)											(In thousands)
Total revenues	$	35,262	$	2,073		$	34,123		$	2,070		$	57,402	$	5,131		$	68,728	$	4,339
Total operating expenses		26,336		2,691			35,518			1,958			49,795		32,924			51,823		5,664
Net income (loss)		8,926		(619	)		(1,396	)		(59	)		7,600		(27,793	)		16,898		(1,326	)

Six months ended
May 31, 2019

Six months ended
May 31, 2018

OGC

OCC

OGC

OCC

(In thousands)

Total revenues

$
68,728

$
4,339

$
69,083

$
4,559

Total operating expenses

51,823

5,664

62,293

4,099

Net income (loss)

16,898

(1,326
)

6,784

121

9.8. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total current		Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total current
	(In thousands)														(In thousands)
Current deferred revenue, January 1, 2019	$	18	$	1,414	$	739	$	7,616	$	1,642	$	38	$	11,467
Current deferred revenue, January 1, 2020															$	18	$	1,933	$	2,860	$	7,014	$	1,630	$	38	$	13,493
Additions		9		1,227		909		10,513		817		19		13,494		2		1,000		4,341		3,095		793		19		9,250
Less revenue recognized		9		790		475		10,528		815		19		12,636		9		967		2,483		3,092		819		19		7,389
Current deferred revenue, June 30, 2019	$	18	$	1,851	$	1,173	$	7,601	$	1,644	$	38	$	12,325
Current deferred revenue, June 30, 2020															$	11	$	1,966	$	4,718	$	7,017	$	1,604	$	38	$	15,354

A rollforward of noncurrent deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total noncurrent		Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total noncurrent
	(In thousands)														(In thousands)
Noncurrent deferred revenue, January 1, 2019	$	21	$	4,393	$	7,284	$	17,942	$	9,628	$	236	$	39,504
Noncurrent deferred revenue, January 1, 2020															$	3	$	3,634	$	7,589	$	17,710	$	9,575	$	198	$	38,709
Additions		—		1,940		1,841		3,372		760		—		7,913		425		3,522		5,582		2,563		764		—		12,856
Less reclassification to current deferred revenue		9		1,665		909		3,797		817		19		7,216		2		967		4,341		3,095		793		19		9,217
Noncurrent deferred revenue, June 30, 2019	$	12	$	4,668	$	8,216	$	17,517	$	9,571	$	217	$	40,201
Noncurrent deferred revenue, June 30, 2020															$	426	$	6,189	$	8,830	$	17,178	$	9,546	$	179	$	42,348

~~10.~~9. DEBT

Debt consisted of the following:

	June 30, 2019			December 31, 2018			June 30, 2020			December 31, 2019
	(In thousands)						(In thousands)
Summit Holdings' variable rate senior secured Revolving Credit Facility (4.91% at June 30, 2019 and 5.03% at December 31, 2018) due May 2022	$	573,000		$	466,000
Summit Holdings' variable rate senior secured Revolving Credit Facility (2.93% at June 30, 2020 and 4.55% at December 31, 2019) due May 2022							$	733,000		$	677,000
Summit Holdings' 8.00% senior secured term loan due March 2021								35,000			—
Summit Holdings' 5.5% senior unsecured notes due August 2022		300,000			300,000			274,224			300,000
Less unamortized debt issuance costs (1)		(2,024	)		(2,362	)		(1,252	)		(1,686	)
Summit Holdings' 5.75% senior unsecured notes due April 2025		500,000			500,000			393,765			500,000
Less unamortized debt issuance costs (1)		(5,412	)		(5,907	)		(3,583	)		(5,015	)
SMP Holdings' variable rate senior secured term loan (7.00% at June 30, 2020 and 7.80% at December 31, 2019) due May 2022								155,200			161,500
Less unamortized debt issuance costs (1)								(3,222	)		(3,974	)
Total debt								1,583,133			1,627,825
Less current portion								38,000			5,546
Total long-term debt	$	1,365,564		$	1,257,731		$	1,545,133		$	1,622,279

(1) Issuance costs are being amortized over the life of the ~~notes.~~term loan and the Senior Notes.

Revolving Credit Facility. Summit Holdings has a senior secured revolving credit facility which allows for revolving loans, letters of credit and ~~swing line~~swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. As of June 30, ~~2019,~~2020, SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of, the indebtedness outstanding under the Revolving Credit Facility. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the Agreement, and the transactions contemplated thereby, and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 1.75% or the adjusted Eurodollar rate, ~~(the LIBOR rate),~~ as defined in the credit agreement, plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At June 30, ~~2019,~~2020, the applicable margin under LIBOR borrowings was ~~2.50% and~~2.75%, the interest rate was ~~4.91%. The~~2.93% and the unused portion of the Revolving Credit Facility totaled ~~$667.9~~$512.9 million, subject to a commitment fee of ~~0.50%~~

0.50%, after giving effect to the issuance thereunder of a ~~$9.1~~$4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of June 30, 2020 was approximately $191 million. See Note 1615 for additional information on our letter of credit.

As of June 30, ~~2019,~~2020, we had $~~7.2~~5.4 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in Other noncurrent assets on the unaudited condensed consolidated balance sheet.

As of and during the six months ended June 30, ~~2019,~~2020, we were in compliance with the Revolving Credit Facility's financial covenants. There were no0 defaults or events of default during the six months ended June 30, ~~2019.~~2020.

Summit Holdings Term Loans. On May 28, 2020, in connection with the closing of the GP Buy-In Transaction, Summit Holdings entered into (i) a Term Loan Credit Agreement (the “ECP NewCo Term Loan Credit Agreement”), with SMP TopCo, LLC, a Delaware limited liability company and affiliate of ECP (“ECP NewCo”), as lender and administrative agent, and Mizuho Bank (USA), as collateral agent (“Mizuho”), in a principal amount of $28.2 million (the “ECP NewCo Loan”), and (ii) a Term Loan Credit Agreement (the “ECP Holdings Term Loan Credit Agreement” and together with the ECP NewCo Term Loan Credit Agreement, the “ECP Term Loan Credit Agreements”), with ECP Holdings, as lender, and ECP NewCo, as administrative agent and Mizuho, as collateral agent, in a principal amount of $6.8 million (the “ECP Holdings Loan” and together with the ECP NewCo Loan, the “ECP Loans”). The ECP Loans mature on March 31, 2021 and are included in the current portion of long-term debt. The ECP Loans under each ECP Term Loan Credit Agreement bear interest at a rate of 8.00% per annum, with the interest expense due at maturity of the ECP Loans.

Also on May 28, 2020 and in connection with the GP Buy-In Transaction, Summit Holdings entered into (i) in connection with the ECP NewCo Term Loan Credit Agreement, a Guarantee and Collateral Agreement (the “ECP NewCo Guarantee”), with the Partnership, the subsidiary guarantors listed therein and Mizuho and (ii) in connection with the ECP Holdings Term Loan Credit Agreement, a Guarantee and Collateral Agreement (the “ECP Holdings Guarantee” and together with the ECP NewCo Guarantee, the “ECP Term Loan Guarantees”), with the Partnership, the subsidiary guarantors listed therein and Mizuho. Pursuant to the ECP Term Loan Guarantees, the obligations under each of the ECP Term Loan Credit Agreements are generally (i) guaranteed by the Partnership and each subsidiary of Summit Holdings that guarantees the obligations under the Revolving Credit Facility, as and to the same extent as such guarantors guarantee the obligations under the Revolving Credit Facility and (ii) secured by a first priority lien on and security interest in all property on which a first priority lien and security interest secures the obligations under the Revolving Credit Facility, in each case, on the terms and subject to the conditions set forth in the ECP Term Loan Credit Agreements.

The ECP Term Loan Credit Agreements each contain affirmative and negative covenants similar to those contained in the Revolving Credit Facility, that, among other things, limit or restrict the ability to (i) incur additional debt; (ii) incur certain liens on property; (iii) make investments; (iv) engage in certain mergers, consolidations, acquisitions or sales of assets; (v) declare or pay certain distributions with respect to equity interests; (vi) enter into certain transactions with any of its affiliates; (vii) enter into swap agreements and power purchase agreements; (viii) enter into certain leases that would cumulatively obligate payments in excess of $50 million over any 12-month period; and (ix) permit any Restricted Subsidiaries (as defined in the ECP Term Loan Credit Agreements) to sell certain industrial revenue bonds to certain parties without the consent of the administrative agent. In addition, the ECP Term Loan Credit Agreements contain maintenance financial covenants substantially similar to those contained in the Revolving Credit Facility, which will require Summit Holdings to maintain, beginning June 30, 2020: (a) 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; (b) a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.50 to 1.00; and (c) a ratio of first lien net indebtedness to consolidated trailing 12-month EBITDA of not more than 3.75 to 1.00. If any of the financial maintenance covenants contained in the Revolving Credit Facility are amended, modified or supplemented, the same financial maintenance covenant in each ECP Term Loan Credit Agreement will automatically be amended in the same manner.

As of June 30, 2020, the Partnership was in compliance with financial covenants of the ECP Loans’ and there were no defaults or events of default existing under either ECP Term Loan Credit Agreement as of June 30, 2020.

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

In February 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes (the "5.75% Senior Notes") maturing April 15, 2025 as described in the ~~2018~~2019 Annual Report.

The Guarantor Subsidiaries are 100% owned by a subsidiary of SMLP. The Guarantor Subsidiaries and SMLP fully and unconditionally and jointly and severally guarantee the ~~5.5% Senior Notes and the 5.75%~~ Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013. We have no other independent assets or operations. At no time have the Senior Notes been guaranteed by the Co-Issuers.

As of and during the six months ended June 30, ~~2019,~~2020, we were in compliance with the covenants governing our Senior ~~Notes. There~~Notes and there were no defaults or events of default during the six months ended June 30, ~~2019.~~2020.

~~11.~~SMP Holdings Term Loan. On March 21, 2017, SMP Holdings entered into a senior secured term loan facility, the SMPH Term Loan, with a maturity date of May 15, 2022, pursuant to which term loans were made to SMP Holdings in the aggregate principal amount of $300.0 million. SMP Holdings became a subsidiary of the Partnership as a result of the GP Buy-In Transaction, and remains liable for the obligations under the SMPH Term Loan. The SMPH Term Loan bears interest at the Eurodollar Rate plus 6.00% or Alternate Base Rate plus 5.00% (each as defined in the SMPH Term Loan), in each case as elected by SMP Holdings in accordance with the SMPH Term Loan. The SMPH Term Loan contains certain customary negative covenants, including, but not limited to, limitations on the incurrence of debt, liens, asset sales and sale leasebacks, investments, dividends, distributions, prepayments, and transactions with affiliates. The SMPH Term Loan also includes a maintenance financial covenant consisting of a minimum interest coverage ratio whereby SMP Holdings is required to maintain a ratio of consolidated trailing 12-month Operating Cash Flow (as defined in the SMPH Term Loan) minus G&A Expenses (as defined in the SMPH Term Loan) paid by SMP Holdings to net interest expense of not less than 2.0 to 1.0 as of the last day of each fiscal quarter of SMP Holdings.

The SMPH Term Loan contains certain customary representations and warranties, affirmative covenants and events of default, including, but not limited to, payment defaults, breaches of representations and warranties, covenant defaults, certain events of insolvency or bankruptcy, material judgments, certain events under ERISA, actual or asserted failures of any guaranty or security document supporting the SMPH Term Loan to be in full force and effect and changes of control.

The obligations related to the SMPH Term Loan are (1) guaranteed by Summit Investments and (2) secured by the following collateral: (i) a perfected first-priority lien on, and pledge of, (A) all of the capital stock issued by SMP Holdings, (B) 34.6 million SMLP common units owned by SMP Holdings, (C) all of the equity interests owned by SMP Holdings in the General Partner, and (ii) substantially all other personal property of SMP Holdings.

Loans under the SMPH Term Loan must be prepaid or there must be an offer to prepay the loans under the SMPH Term Loan under certain circumstancesinvolving the activities of Summit Investments, including with proceeds from certain future debt issuances, asset sales and a portion of excess cash flow for the applicable fiscal quarter. Loans under the SMPH Term Loan may be voluntarily prepaid at any time, subject to certain redemption prices and customary LIBOR breakage costs.

SMP Holdings is required to repay principal amounts outstanding under the SMPH Term Loan quarterly in an amount equal to 1.0% per annum of the original principal amount of the loans under the SMPH Term Loan. SMP Holdings’ current portion of long-term debt includes scheduled principal amortization. We were not required to make an excess cash flow payment on the SMPH Term Loan for the second quarter of 2020, and have not included an estimated excess cash flow amount in the current portion of long-term debt relating to the third and fourth quarter of 2020 and

the first quarter of 2021 because the amount is not currently estimable given that the excess cash flow calculation is based on the occurrence of future events.

On April 17, 2020, we entered into a derivative financial instrument to convert a portion of our variable rate SMPH Term Loan to a fixed rate debt consisting of a 1% LIBOR interest rate cap for a fee of $0.2 million (exclusive of the applicable bank margin charged by our lender) on a $125.0 million notional amount beginning April 30, 2020 and ending on April 30, 2022. We have not designated the interest rate cap for hedge accounting as defined by GAAP and recognized an unsettled gain of $0.1 million on the interest rate cap in the other income line item on our unaudited condensed consolidated statement of operations for the three and six month periods ended June 30, 2020.

As of June 30, 2020, SMP Holdings was in compliance with the SMPH Term Loan’s financial covenants and there were no defaults or events of default existing under the SMPH Term Loan as of June 30, 2020.

Repurchases.Subsequent to the GP Buy-In Transaction, the Partnership commenced a debt buyback program to repurchase our Senior Notes, which is ongoing. We repurchased $25.8 million of the outstanding $300 million aggregate principal amount of our 5.50% Senior Notes through June 30, 2020. The gain on early extinguishment of debt for the 5.50% Senior Notes during the three and six months ended June 30, 2020 totaled $9.2 million and is inclusive of a $0.1 million write off of debt issuance costs. We also repurchased $106.2 million of the outstanding $500 million aggregate principal amount of our 5.75% Senior Notes through June 30, 2020. The gain on early extinguishment of debt for the 5.75% Senior Notes during the three and six months ended June 30, 2020 totaled $45.1 million and is inclusive of a $1.0 million write off of debt issuance costs.

10. FINANCIAL INSTRUMENTS

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

Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit or other forms of credit assurance for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top ~~five~~5 customers or counterparties accounted for 50% of total accounts receivable as of June 30, ~~2019,~~2020, compared with ~~39%~~46% as of December 31, ~~2018.~~2019.

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

The Deferred Purchase Price Obligation's carrying value is its fair value because carrying value represents the present value of the payment expected to be made in 2020. In March 2019, the Partnership amended the Contribution Agreement related to the 2016 Drop Down and fixed the Remaining Consideration at $303.5 million, with such amount to be paid by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020 (see Note 17 for additional information).

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

	June 30, 2019				December 31, 2018				June 30, 2020				December 31, 2019
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)								(In thousands)
Summit Holdings 5.5% Senior Notes ($300.0 million principal)	$	297,976	$	287,750	$	297,638	$	286,625	$	272,973	$	180,531	$	298,314	$	266,750
Summit Holdings 5.75% Senior Notes ($500.0 million principal)		494,588		437,500		494,093		455,208		390,183		211,977		494,985		382,708

The carrying ~~value~~values on the balance sheet of the Revolving Credit Facility ~~is its~~and the SMPH Term Loan are their fair ~~value~~values due ~~to its~~their floating interest ~~rate.~~rates. The ~~estimated~~ fair value for the Senior Notes is based on an average of nonbinding broker quotes as of June 30, ~~2019~~2020 and December 31, ~~2018.~~2019. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

~~12.~~11. PARTNERS' CAPITAL AND MEZZANINE CAPITAL

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

Limited partners

Series A Preferred Units

Common

General
Partner

Units, January 1, 2019

300,000

73,390,853

1,490,999

Conversion of General Partner economic interests

—

8,750,000

(1,490,999
)
Net units issued under the SMLP LTIP

—

564,038

—

Units, June 30, 2019

300,000

82,704,891

—

	Common Units
Units, December 31, 2019 (1)		45,318,866
Net units issued under the SMLP LTIP		308,364
Impact of GP Buy-In Transaction		(2,084,174	)
Units, June 30, 2020 (1)		43,543,056

~~GP/IDR Exchange.~~ On March 22, 2019, we cancelled our IDRs and converted our 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units which were issued to SMP Holdings in the Equity Restructuring. These units had a fair value of $84.5 million as of the transaction date (March 22, 2019).(1) As a result of the ~~Equity Restructuring,~~GP Buy-In Transaction, the ~~general~~recast of the historical financial statements resulted in a recasted common limited partner unit count of 45.3 million units at December 31, 2019. Prior to the GP Buy-In Transaction, the common limited partner unit count was 93.5 million units at December 31, 2019, and after adjusting these 93.5 million units for the effect of 1.2 million units issued through June 30, 2020 for the SMLP LTIP, and the GP Buy-In Transaction’s repurchase of 34.6 million units pledged under the Term Loan B, the 10.7 million units not pledged under the Term Loan B, and the 5.9 million units owned by ECP, the common limited partner unit count would have been an otherwise identical 43.5 million common limited partner units ~~and IDRs were eliminated, are no longer outstanding, and no longer participate~~at June 30, 2020.

GP Buy-In Transaction. The purchase price for the common units reflected in ~~distributions~~the unaudited condensed consolidated statement of ~~cash from SMLP. ECP continues to control~~partners’ capital for the ~~non-economic GP interest in SMLP.~~

Immediately following the Equity Restructuring, SMP Holdings directly owned a 41.8% limited partner interest in SMLP and an affiliate of Energy Capital Partners II, LLC directly owned a 7.2% limited partner interest in SMLP.

~~For the three and~~ six months ended June 30, ~~2018, our general partner held IDRs that entitled it to receive increasing percentage allocations, up to a maximum of 50%,~~2020 is comprised of the (i) the $35.0 million cash ~~we distributed from operating surplus in excess of $0.46 per unit per quarter.~~

~~Our~~ payment ~~of IDRs as reported in distributions~~ to ~~unitholders – general partner in~~ECP, (ii) the ~~statement of partners' capital during the three and six months ended June 30 follow.~~

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

(In thousands)

IDR payments

$
—

$
2,136

$
2,139

$
4,264

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

~~At-the-market Program.In 2017, we executed an equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC~~$2.3 million fair value for the issuance of 10,000,000 warrants, (iii) and ~~sale from time~~$6.8 million of advisory fees and other direct costs related to ~~time of SMLPcommon units having an aggregate offering price of up to$150.0 million~~(closing the "ATM Program"). These sales will be made (i) pursuant to the terms of the equity distribution agreement between us and the sales agents named therein and (ii) by means of ordinary brokers' transactions at market prices, in block transactions or as otherwise agreed between us and the sales agents. Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rulesGP Buy-In Transaction. .

~~During the three and six months ended June 30, 2019, there were no~~transactions under the ATM Program. Following the effectiveness of the ATM Program registration statement and after taking into account the aggregate sales price of common units sold under the ATM Program through June 30, 2019, we have the capacity to issue additional common units under the ATM Program up to an aggregate~~$132.3 million.~~

Series A Preferred Units. In 2017, we issued 300,000 Series A ~~Fixed-to-Floating Rate Cumulative Redeemable Perpetual~~ Preferred Units ~~(the “Series A Preferred Units”)~~ representing limited partner interests in the Partnership at a price to the public of $1,000 per unit as described in the ~~2018~~2019 Annual Report. In connection with the GP Buy-In Transaction,the Partnership suspended its distributions to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. On June 18, 2020, the Partnership, commenced an offer to exchange any and all of its Series A Preferred Units for newly issued common units (the “Exchange Offer”). As of June 30, 2020, the Exchange Offer was still pending. See Note 17 for additional details on the Exchange Offer.

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

During the six months ended June 30, 2020, we issued an additional 50,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $48.7 million (after deducting underwriting discounts and offering expenses) to fund our share of capital expenses associated with the Double E Project.

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

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

The ECP Warrants also provide that the Partnership will file a registration statement to register the common units issuable upon exercise of the ECP Warrants no later than 90 days following the Closing Date and use commercially reasonable efforts to cause such registration statement to become effective.

Upon exercise of the ECP Warrants, each of ECP NewCo and ECP Holdings may receive, at its election: (i) a number of common units equal to the number of common units for which the ECP Warrant is being exercised, if exercising the ECP Warrant by cash payment of the exercise price; (ii) a number of 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 common units on the New York Stock Exchange (the “NYSE”) on each of the three

trading days prior to the delivery of the notice of exercise (the “VWAP Average”) and the exercise price (the “VWAP Difference”), divided by (b) the VWAP Average; and/or (iii) an amount in cash, to the extent that the Partnership’s leverage ratio would be at least 0.5x less than the maximum applicable ratio set forth in the Revolving Credit Facility, equal to the product of (a) the number of 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 and recapitalizations and are exercisable at any time after the Closing Date and on or before the third anniversary of the Closing Date. Upon exercise of the ECP Warrants, the proceeds to the holders of the ECP Warrants, whether in the form of cash or common units, will be capped at $2.00 per common unit above the exercise price.

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

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

Cash Distributions Paid and Declared. WePrior to the GP Buy-In Transaction, SMLP paid the following per-unit distributions during the three and six months ended June 30 (All payments represent per-unit distributions based on the SMLP common units outstanding prior to the GP Buy-In Transaction)::

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

Per-unit distributions to unitholders

$
0.2875

$
0.575

$
0.8625

$
1.150

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
Per-unit distributions to unitholders	$	—	$	0.2875	$	0.125	$	0.8625

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

~~On July 25, 2019,~~With respect to our Subsidiary Series A Preferred Units relating to the ~~Board~~three and six months ended June 30, 2020, we declared a payment-in-kind ("PIK") of ~~Directors~~the quarterly distribution, which resulted in the issuance of ~~our General Partner declared~~490 Subsidiary Series A Preferred Units and 1,397 Subsidiary Series A Preferred Units, respectively. This PIK amount equates to a distribution of ~~$0.2875~~$30.7320 and $17.2579 per ~~unit~~Subsidiary Series A Preferred Unit for the ~~quarterly period~~three and six months ended June 30, ~~2019. This distribution, which totaled $23.8 million, will be paid~~2020, respectively, or $70 on ~~August 14, 2019~~an annualized basis. In addition, we issued approximately 38 Subsidiary Series A Preferred Units related to ~~unitholders~~the remaining undrawn commitment (as defined in the underlying agreement with TPG Energy Solutions Anthem, L.P.) as of ~~record at~~and for the ~~close of business on August 7, 2019.~~six months ended June 30, 2020.

~~13.~~12. EARNINGS PER UNIT

The following table details the components of EPU.

	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,					Six months ended June 30,
	2019			2018			2019			2018			2020		2019			2020		2019
	(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) attributable to limited partners	$	4,809		$	(51,111	)	$	(32,117	)	$	(57,099	)	$	58,114	$	4,369		$	63,757	$	(10,341	)
Less net income attributable to Series A Preferred Units		7,125			7,125			14,250			14,250			7,125		7,125			14,250		14,250
Net loss attributable to common limited partners	$	(2,316	)	$	(58,236	)	$	(46,367	)	$	(71,349	)
Less net income attributable to Subsidiary Series A Preferred Units														1,397		—			2,342		—
Net income (loss) attributable to common limited partners													$	49,592	$	(2,756	)	$	47,165	$	(24,591	)

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic and diluted		82,700			73,356			79,266			73,245
Weighted-average common units outstanding – basic (1)														44,650		45,319			44,985		45,319
Effect of nonvested phantom units														2,087		—			1,338		—
Weighted-average common units outstanding – diluted														46,737		45,319			46,323		45,319

Loss per limited partner unit:
Income (Loss) per limited partner unit:
Common unit – basic	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)	$	1.11	$	(0.06	)	$	1.05	$	(0.54	)
Common unit – diluted	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)	$	1.06	$	(0.06	)	$	1.02	$	(0.54	)

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		—			1			17			3			4,139		—			3,014		17

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

~~14.~~As discussed in Note 9, the SMPH Term Loan is secured by 34.6 million SMLP common units owned by SMP Holdings. These common units are not included in the calculation of EPU because they are not deemed contingently issuable under GAAP.

13. UNIT-BASED AND NONCASH COMPENSATION

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

•

In March ~~2019,~~2020, we granted ~~639,522~~3,811,301 phantom units and associated distribution equivalent rights to employees in connection with our annual incentive compensation award cycle. These awards had a grant date fair value of $~~9.78~~0.55 and vest ratably over a three-year period.

•

In March ~~2019,~~2020, we also issued ~~16,358~~549,450 common units to our ~~two~~3 independent directors in connection with their annual compensation plan.

•

In ~~May 2019,~~June 2020, we issued ~~an additional 9,580~~187,500 common units to an3 new independent ~~director~~directors in ~~conjunction~~connection with ~~his appointment to our Board of Directors.~~their annual compensation plan.

•

During the six months ended June 30, ~~2019, 562,660~~2020, 539,721 phantom units vested.

•

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

•

As of June 30, ~~2019,~~2020, approximately ~~2.6~~6.7 million common units remained available for future issuance under the SMLP LTIP.

~~15.~~14. RELATED-PARTY TRANSACTIONS

Acquisitions. See Notes 121 and 17 of the ~~2018~~2019 Annual Report.

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

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

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

(In thousands)

Operation and maintenance expense

$
7,560

$
7,114

$
15,445

$
14,737

General and administrative expense

6,135

7,481

16,965

15,598

~~16.~~15. LEASES, COMMITMENTS AND CONTINGENCIES

Leases. We account for leases in accordance with Topic 842, which we adopted on January 1, 2019, using the modified retrospective method. Under the modified retrospective method, the comparative information is not adjusted and is reported under the accounting standards in effect for those periods. See Note 2 for further discussion of the adoption.

We and Summit Investments lease certain office space and equipment under operating leases. We lease office space for our corporate headquarters as well as for offices in and around our gathering systems for terms of between 3 and 10 years. We lease the office space to limit exposure to risks related to ownership, such as fluctuations in real estate prices. In addition, we lease equipment primarily to support our operations in response to the needs of our gathering systems for terms of between 3 and 4 years. We and Summit Investments also lease vehicles under finance leases to support our operations in response to the needs of our gathering systems for a term of 3 years. We only lease from reputable companies and our leased assets are not specialized in our industry.

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

We have options to extend the lease term of certain office space in Texas, Colorado and West Virginia. The beginning of the noncancelable lease period for these leases range from 2014 to 2018 and the lease period ends between 2019 and 2021. These lease agreements contain between one and three options to renew the lease for a period of between two and five years. As of June 30, 2019, the exercise of the renewal options for these leases are not reasonably certain and, as a result, the payments associated with these renewals are not included in the measurement of the lease liability and ROU asset.

We also have options to extend the lease term of certain compression equipment used at the Summit Utica gathering system. The beginning of the noncancelable lease period for these leases is 2017 and the lease period ends in 2020. Upon expiration of the noncancelable lease period, we have the option to renew the leases on a month-to-month basis; we therefore have not included any amounts attributable to renewals in the measurement.

~~Our leases do not contain residual value guarantees.~~

In accordance with the provisions in our Revolving Credit Facility, our aggregate finance lease obligations cannot exceed the greater of $50 million or 5.5% of consolidated total assets in any period of twelve consecutive calendar months during the life of such leases.

In March 2019, we entered into an agreement with a third party vendor to construct a transmission line to deliver electric power to the new 60 MMcf/d processing plant under development in the DJ Basin. The project was expected to cost approximately $7.8 million and we made an up-front payment of $3.0 million which is included in the Property, plant and equipment, net caption on the unaudited condensed consolidated balance sheet. During the second quarter of 2019, we exercised an option to increase the capacity of the transmission line for an additional cost of $4.3 million and we issued an irrevocable standby letter of credit payable to the vendor with an initial term of one year totaling $9.1 million, which reflects the expected remaining cost of the project. The letter of credit will automatically renew for successive twelve month periods following the initial term, subject to certain adjustments. Once construction is complete, the letter of credit will be adjusted to reflect the final construction cost. We determined the contract contained a lease based on the right to use the constructed transmission line to power the processing plant in the DJ Basin. The project is expected to be completed and the commencement date of the ROU asset will be on or before July 1, 2020.

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

The rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term used. Our incremental borrowing rate on the Revolving Credit Facility was 5.03% at December 31, 2018, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.

We adopted the following practical expedients in Topic 842 for all asset classes, which included (i) not being required to reassess whether any expired or existing contracts are or contain leases; (ii) not being required to reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will be classified as finance leases); (iii) not being required to reassess initial direct costs for any existing leases; (iv) not recognizing ROU assets and lease liabilities that arise from short-term leases of twelve months or less for any class of underlying asset; (v) not allocating consideration in a contract between lease and nonlease (e.g., maintenance services) components for our leased office space and equipment; and (vi) not evaluating existing or expired land easements that were not previously accounted for as leases under Topic 840.

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

	June 30,
	2019		June 30, 2020		December 31, 2019
	(In thousands)		(In thousands)

ROU assets
Operating	$	5,136	$	4,996	$	3,580
Finance		4,061		2,253		3,159
	$	9,197	$	7,249	$	6,739
Lease liabilities, current
Operating	$	2,337	$	1,659	$	1,221
Finance		1,627		826		1,246
	$	3,964	$	2,485	$	2,467
Lease liabilities, noncurrent
Operating	$	2,996	$	4,120	$	2,513
Finance		1,194		310		676
	$	4,190	$	4,430	$	3,189

~~Lease cost and Other information follow:~~

Three months ended

Six months ended

June 30, 2019

June 30, 2019

(In thousands)

Lease cost

Finance lease cost:

Amortization of ROU assets (included in depreciation and amortization)

$
407

$
775

Interest on lease liabilities (included in interest expense)

30

53

Operating lease cost (included in general and administrative expense)

745

1,577

$
1,182

$
2,405

Six months ended

June 30, 2019

(In thousands)

Other information

Cash paid for amounts included in the measurement of lease liabilities

Operating cash outflows from operating leases

$
1,678

Operating cash outflows from finance leases

53

Financing cash outflows from finance leases

915

ROU assets obtained in exchange for new operating lease
liabilities

1,218

ROU assets obtained in exchange for new finance lease
liabilities

1,292

Weighted-average remaining lease term (years) - operating leases

4.9

Weighted-average remaining lease term (years) - finance leases

2.0

Weighted-average discount rate - operating leases

5
%
Weighted-average discount rate - finance leases

4
%

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

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018

(In thousands)

Lease expense

$
986

$
956

$
1,930

$
1,978

~~Future minimum lease payments due under noncancelable leases for the remainder of 2019 and each of the five succeeding fiscal years and thereafter, were as follows:~~

June 30, 2019

(In thousands)

Operating

Finance

2019

$
1,738

$
898

2020

1,606

1,348

2021

1,001

621

2022

538

70

2023

400

—

2024

240

—

Thereafter

895

—

Total future minimum lease payments

$
6,418

$
2,937

~~Future minimum lease payments due under noncancelable operating leases (under ASC 840) at December 31, 2018, were as follows:~~

December 31,

2018

(In thousands)

2019

$
3,133

2020

1,018

2021

550

2022

506

2023

373

Thereafter

621

Total future minimum lease payments

$
6,201

~~Future payments due under finance leases (under ASC 840) at December 31, 2018, were as follows:~~

December 31,

2018

(In thousands)

2019

$
1,473

2020

902

2021

174

Total finance lease obligations

2,549

Less: Amounts representing interest

(104
)
Net present value of finance lease obligations

2,445

Less: Amount representing current portion (included in Other current liabilities)

(1,406
)
Finance lease obligations, less current portion (included in Other noncurrent liabilities)

$
1,039

	Three months ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
Lease expense	$	937	$	1,033	$	1,890	$	2,023

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

~~As described in the 2018 Annual Report, in~~In 2015, ~~Summit Investments~~we learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, which was covered by ~~Summit Investments'~~ insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. ~~Summit Investments exhausted the~~ ~~$25.0 million~~The pollution liability policy was exhausted in 2015.

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

Total

(In thousands)

Accrued environmental remediation, January 1, 2019

$
5,636

Payments made

(1,001
)
Additional accruals

767

Accrued environmental remediation, June 30, 2019

$
5,402

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2020	$	4,651
Payments made		(545	)
Accrued environmental remediation, June 30, 2020	$	4,106

As of June 30, ~~2019,~~2020, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to June 30, ~~2020.~~2021. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

~~While we cannot predict~~Prior to the ~~ultimate outcome of this matter with certainty for~~GP Buy-In Transaction, Summit Investments ~~or Meadowlark Midstream, especially as it relates~~and SMP Holdings indemnified the Partnership for certain obligations and liabilities related to ~~any material liability as~~the incident. As a result of ~~any governmental proceeding~~the GP Buy-In Transaction, the Partnership is no longer indemnified for these obligations by a third party.

The U.S. Department of Justice issued grand jury subpoenas to the Partnership requesting certain materials related to the ~~incident, we believe at this time that it is unlikely that SMLP or its General Partner will be subject to any material liability as a result of any governmental proceeding related~~Meadowlark Midstream rupture. Based on information currently available to the ~~rupture.~~Partnership, the Partnership believes a loss for claims and/or actions arising from the Meadowlark Midstream rupture is probable. Due to the complexity surrounding the resolution of the Meadowlark Midstream rupture, the Partnership is not able to reasonably estimate the extent of the Partnership’s loss for this matter, or to express an opinion regarding the ultimate outcome. Any such loss, if incurred, could be material.

Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.

~~17.~~16. DISPOSITIONS ~~ACQUISITIONS~~ AND ~~DROP DOWN TRANSACTIONS~~RESTRUCTURING

Tioga Midstream Disposition. In February 2019, Tioga Midstream, LLC, a subsidiary of SMLP, and certain affiliates of SMLP (collectively, “Summit”) entered into ~~two~~2 Purchase and Sale Agreements (the “Tioga PSAs”) with Hess Infrastructure Partners LP and Hess North Dakota Pipelines LLC (collectively, “Hess Infrastructure”), pursuant to which Summit agreed to sell the Tioga Midstream system to Hess Infrastructure for a combined cash purchase price of $90 million, subject to adjustments as provided in the Tioga PSAs (the “Tioga Midstream Sale”). On March 22, 2019, Summit closed the Tioga Midstream Sale and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

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

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

In March 2019, the Partnership amended the Contribution Agreement related to the 2016 Drop Down and fixed the Remaining Consideration at $303.5 million, with such amount to be paid by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii)As a ~~combination of cash and the Partnership’s common units, at the discretion~~result of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020.

~~The present value~~GP Buy-In Transaction (Refer to Note 1 for additional details), SMP Holdings transferred its right to receive payment of the Deferred Purchase Price Obligation under the Contribution Agreement. Under the Contribution Agreement, the Partnership is ~~reflected as a liability on our balance sheet until paid. As of June 30, 2019,~~now required to pay the ~~Remaining Consideration, which reflects~~remaining consideration under the ~~net present value of~~Contribution Agreement to its subsidiary, Summit Contribution Holdings, LLC, by January 15, 2022. Because this obligation is owed to the ~~$303.5 million Deferred Purchase Price Obligation, was $292.1 million on~~Partnership’s own subsidiary, the unaudited condensed consolidated balance sheet ~~using~~as of June 30, 2020 and December 31, 2019 reflects no liabilities associated with this obligation.

Restructuring Activities.As of December 31, 2019, we had $3.3 million of unpaid employee severance costs related to 2019 restructuring initiatives that resulted in certain management, facility and organizational changes. During the three- and six-month periods ended June 30, 2020, our 2019 restructuring initiatives resulted in additional restructuring costs of $0.6 million and $3.3 million, respectively. We paid out $5.7 million of these 2019 restructuring costs during the six months ended June 30, 2020 and have a ~~discount rate~~$0.9 million current liability for unpaid employee severance costs at June 30, 2020 related to these 2019 restructuring initiatives. The 2019 restructuring activities primarily consisted of ~~5.25%.~~employee-related costs and consulting costs in support of the restructuring initiatives. Restructuring costs are included within the General and administrative caption on the condensed consolidated statement of operations.

~~18.~~17. SUBSEQUENT EVENTS

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

The Exchange Offer expired on July 28, 2020 and the Partnership exchanged 62,816 Series A Preferred Units at a ratio of 200 common units per Series A Preferred Unit for a total of 12,563,200 common units, subject to applicable

withholding taxes. Upon completion of the Exchange Offer, 237,184 Series A Preferred Units were not tendered and remain outstanding.

Subsequent to June 30, 2020 and through August 6, 2020, we have repurchased approximately $5.9 million face value of Summit Holdings and Finance Corp 5.5% senior unsecured notes due August 2022 at a weighted average 34% discount for approximately $3.9 million in cash.

On August 7, 2020, we repaid all amounts outstanding under the ECP Loans which included $35 million of principal and $0.6 million of accrued interest.The ECP Loan repayment was financed in full with borrowings drawn under our Revolving Credit Facility.

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&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries for the periods since December 31, ~~2018.~~2019. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the ~~2018~~2019 Annual Report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.

This MD&A comprises the following sections:

•

Overview

•

Trends and Outlook

•

How We Evaluate Our Operations

•

Results of Operations

•

Liquidity and Capital Resources

•

Critical Accounting Estimates

•

Forward-Looking Statements

Overview

We are a ~~growth-oriented~~value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in ~~the core producing areas of~~ unconventional resource basins, primarily shale formations, in the continental United States.

We classify our midstream energy infrastructure assets into two categories:

•

Core Focus Areas – ~~production~~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 ~~moderate~~reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas.

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

•

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

•

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

•

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

•

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

•

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

•

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

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

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian ~~and Grand River~~ systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the three and six months ended June 30, ~~2019,~~2020, these additional activities accounted for approximately ~~18%~~12% of total revenues including marketing transactions, and approximately 15% of total revenues excluding marketing transactions. During the six months ended June 30, 2019, these additional activities accounted for approximately 24% of total revenues including marketing transactions, and approximately 13% of total revenues excluding marketing transactions.revenues.

We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the "Segment Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018"~~2019" section herein.

	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018			2020			2019			2020			2019
	(In thousands)												(In thousands)
Net income (loss)	$	4,809		$	(49,913	)	$	(32,105	)	$	(53,758	)	$	56,721		$	3,028		$	60,483		$	(37,252	)
Reportable segment adjusted EBITDA
Utica Shale	$	6,640		$	9,223		$	12,833		$	17,938		$	10,693		$	6,640		$	16,621		$	12,833
Ohio Gathering		9,939			8,935			19,149			19,412			7,514			9,939			15,453			19,149
Williston Basin		16,650			19,030			35,384			35,000			12,727			16,650			28,919			35,384
DJ Basin		2,816			959			5,489			2,280			4,339			2,816			10,250			5,489
Permian Basin		(656	)		—			(1,206	)		—			1,828			(656	)		3,409			(1,206	)
Piceance Basin		24,584			26,714			50,583			54,628			21,734			24,584			45,291			50,583
Barnett Shale		11,208			11,093			22,582			20,952			8,510			11,208			17,270			22,582
Marcellus Shale		4,635			6,543			9,777			13,219			4,888			4,635			10,208			9,777

Net cash provided by operating activities	$	43,535		$	58,839		$	96,246		$	110,049		$	35,170		$	39,381		$	105,371		$	84,574
Capital expenditures (1)		50,244			49,616			111,092			90,394			8,843			50,244			27,426			111,092
Investment in equity method investee														21,695			5,921			79,728			5,921

Distributions to common unitholders	$	23,775		$	45,216		$	69,056		$	90,269
Distributions to common SMLP unitholders													$	—		$	13,826		$	6,037		$	41,200
Distributions to Series A Preferred unitholders		14,250			14,250			14,250			14,250			—			14,250			—			14,250
Net borrowings under Revolving Credit Facility		139,000			55,000			107,000			95,000
Net borrowings (repayments) under Revolving Credit Facility														35,000			139,000			56,000			107,000
Repayments on SMP Holdings term loan														(5,550	)		(41,500	)		(6,300	)		(53,750	)
Repurchase of Senior Notes														(76,707	)		—			(76,707	)		—
Proceeds from issuance of Subsidiary Series A preferred units, net of costs (2)														14,764			—			48,710			—
Purchase of common units in GP Buy-In Transaction (3)														(41,778	)		—			(41,778	)		—

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

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

(3) Following the closing of the GP Buy-In Transaction, in May 2020, we commenced a debt buyback program on our Senior Notes, which is ongoing. We repurchased $25.8 million of the outstanding $300 million aggregate principal amount of our 5.50% Senior Notes through June 30, 2020. The gain on early extinguishment of debt for the 5.50% Senior Notes during the three and six months ended June 30, 2020 totaled $9.2 million and is inclusive of the write off of debt issuance costs of $0.1 million. We also repurchased $106.2 million of the outstanding $500 million aggregate principal amount of our 5.75% Senior Notes through June 30, 2020. The gain on early extinguishment of debt for the 5.75% Senior Notes during the three and six months ended June 30, 2020 totaled $45.1 million and is inclusive of the write off of debt issuance costs of $1.0 million.

Three and six months ended June 30, 2020.The following items are reflected in our financial results:

•

In May 2020, we closed on the GP Buy-In Transaction. Refer to Note 1 of the notes to unaudited condensed consolidated financial statements for details.

Three and six months ended June 30, 2019. The following items are reflected in our financial results:

•

In June 2019, we decided to proceed with the Double E Project after securing firm 10-year take-or-pay commitments for a substantial majority of the pipeline’s initial throughput capacity of 1.35 billion cubic feet of gas per day and executing the JV Agreement with an affiliate of Double E’s foundation shipper. ~~Double E filed its Section 7(c) application with the Federal Energy Regulatory Commission on July 31, 2019.~~

In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. We ~~expect to~~ own a majority interest in the ~~Project, to lead the development, permitting and construction of the~~Double E Project and are leading efforts to develop, permit and construct the pipeline. Upon commissioning, we will operate the ~~pipeline upon commissioning.~~pipeline. We estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $350.0 million, and that more than 90% of those capital

expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the requisite regulatory approvals, we expect that the Double E Project will be placed into service in the third quarter of 2021.

•

~~Until~~In March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering systems operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota. Refer to Note 17 for details on the sale of Tioga Midstream. On March 22, 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

•

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

The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet. As of June 30, 2019, the Remaining Consideration, which reflects the net present value of the $303.5 million Deferred Purchase Price Obligation, was $292.1 million on the unaudited condensed consolidated balance sheet using a discount rate of 5.25%. We have presented the Deferred Purchase Price Obligation as a current liability based on the expected settlement on or before June 30, 2020.

•

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

•

In March 2019, certain events ~~facts and circumstances~~ occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our existing 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets ~~would be shut down~~were impaired and ~~de-commissioned and we~~ recorded an impairment charge of $10.2 ~~million related to these assets.~~

~~Three and six months ended June 30, 2018.The following items are reflected in our financial results:~~

•

During the three and six months ended June 30, 2018, we recognized $6.0 million and $8.4 million, respectively in gathering services and related fees from MVC shortfall adjustments. Under Topic 606, we recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.million.

Trends and Outlook

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

•

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

•

Production from U.S. shale plays;

•

Capital markets ~~activity~~availability and cost of capital; ~~and~~

•

Shifts in operating costs and ~~inflation.~~inflation; and

•

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

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

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

operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.

In addition, the COVID-19 pandemic has significantly reduced the global demand for oil and natural gas. This significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, or OPEC, and other foreign, oil-exporting countries. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, there is no assurance that the agreement will continue to be observed by its parties and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Such responses could cause our pipelines and storage tanks and other third party storage facilities to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products.

Over the past several months, we have collaborated extensively with our customer base regarding reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given further deterioration of market conditions since March and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity and the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. For example, in the Utica Shale, a customer has recently curtailed in excess of 150 MMcf/d of production which the Partnership now expects will remain offline awaiting more favorable natural gas prices in late 2020 and into 2021, and we recently amended gathering contracts with two key Williston Basin customers to extend the terms of the gathering agreement acreage dedications, in exchange for a modest gathering fee concession. Accordingly, given reduced producer activity across our footprint, we expect 2020 total capital expenditures to range from of $30 million to $50 million.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the ~~2018~~2019 Annual Report.

How We Evaluate Our Operations

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

•

the Utica Shale, which is served by Summit Utica;

•

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

•

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

•

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

•

the Permian Basin, which is served by Summit Permian;

•

the Piceance Basin, which is served by Grand River;

•

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

•

the Marcellus Shale, which is served by Mountaineer Midstream.

Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston ~~Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota.~~Basin. Refer to Note 1716 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream.

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

•

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, ~~2019.~~2020.

Additional Information. For additional information, see the "Results of Operations" section herein and the notes to the unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the "How We Evaluate Our Operations" section of MD&A included in the ~~2018~~2019 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.

Results of Operations

Consolidated Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019

The following table presents certain consolidated and operating data.

	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018			2020			2019			2020			2019
	(In thousands)												(In thousands)
Revenues:
Gathering services and related fees	$	75,107		$	89,585		$	162,071		$	173,946		$	73,911		$	75,107		$	157,703		$	162,071
Natural gas, NGLs and condensate sales		18,291			31,891			56,219			58,008			10,683			18,291			24,463			56,219
Other revenues		6,288			6,707			12,804			13,549			7,413			6,288			14,744			12,804
Total revenues		99,686			128,183			231,094			245,503			92,007			99,686			196,910			231,094
Costs and expenses:
Cost of natural gas and NGLs		11,571			24,384			43,330			44,670			6,088			11,571			14,313			43,330
Operation and maintenance		23,718			24,466			47,940			49,070			21,152			24,318			42,963			48,540
General and administrative		10,214			13,484			27,495			27,926			12,786			10,565			29,347			28,950
Depreciation and amortization		26,800			26,784			54,527			53,461			29,630			26,837			59,296			54,601
Transaction costs		—			—			950			—			1,207			96			1,218			2,433
(Gain) loss on asset sales, net		(287	)		62			(1,248	)		(12	)
Gain on asset sales, net														(281	)		(287	)		(166	)		(1,248	)
Long-lived asset impairment		70			587			45,021			587			654			70			4,475			45,021
Total costs and expenses		72,086			89,767			218,015			175,702			71,236			73,170			151,446			221,627
Other income		83			27			292			20
Other income (expense)														276			83			(151	)		292
Interest expense		(17,941	)		(14,837	)		(35,468	)		(29,959	)		(21,990	)		(22,343	)		(45,818	)		(45,085	)
Deferred Purchase Price Obligation		(3,712	)		(69,305	)		(8,139	)		(90,963	)
Income (loss) before income taxes and loss from equity method investees		6,030			(45,699	)		(30,236	)		(51,101	)
Income tax expense		(1,142	)		(294	)		(1,349	)		(123	)
Loss from equity method investees		(79	)		(3,920	)		(520	)		(2,534	)
Gain on early extinguishment of debt														54,235			—			54,235			—
Income (loss) before income taxes and income (loss) loss from equity method investees														53,292			4,256			53,730			(35,326	)
Income tax benefit (expense)														389			(1,149	)		402			(1,406	)
Income (loss) from equity method investees														3,040			(79	)		6,351			(520	)
Net income (loss)	$	4,809		$	(49,913	)	$	(32,105	)	$	(53,758	)	$	56,721		$	3,028		$	60,483		$	(37,252	)

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,368			1,797			1,419			1,767			1,391			1,368			1,336			1,419
Aggregate average daily throughput - liquids (Mbbl/d)		94.3			88.9			98.6			86.9			76			94.3			87.0			98.6

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

Volumes – Gas. Natural gas throughput volumes ~~decreased 429~~increased 23 MMcf/d for the three months ended June 30, 2020 compared to the three months ended June 30, ~~2018,~~2019, primarily reflecting:

•

a volume throughput increase of 156 MMcf/d for the Utica Shale segment.

•

a volume throughput increase of 15 MMcf/d for the Permian Basin segment.

•

a volume throughput decrease of ~~177~~95 MMcf/d for the Piceance Basin segment.

•

a volume throughput decrease of 48 MMcf/d for the Barnett Shale segment.

Natural gas throughput volumes decreased 83 MMcf/d for the six months ended June 30, 2020 compared to the six months ended June 30, 2019, primarily reflecting:

•

a volume throughput decrease of 98 MMcf/d for the Piceance Basin segment.

•

a volume throughput decrease of 42 MMcf/d for the Barnett Shale segment.

•

a volume throughput decrease of 12 MMcf/d for the Marcellus Shale segment.

•

a volume throughput ~~decrease~~increase of ~~155~~46 MMcf/d for the Utica Shale segment.

•

a volume throughput ~~decrease~~increase of 9817 MMcf/d for the ~~Piceance Basin segment.~~

~~Natural gas throughput volumes decreased 348 MMcf/d compared to the six months ended June 30, 2018, primarily reflecting:~~

•

~~a volume throughput decrease of 160 MMcf/d for the Marcellus Shale segment.~~

•

~~a volume throughput decrease of 113 MMcf/d for the Utica Shale segment.~~

•

~~a volume throughput decrease of 89 MMcf/d for the Piceance~~Permian Basin segment.

Volumes – Liquids. Crude oil and produced water throughput volumes inat the Williston ~~Basin~~ segment ~~increased 5.4~~decreased 18.3 Mbbl/d and ~~11.7~~11.6 Mbbl/d for the three and six months ended June 30, 2020, respectively, compared to the three and six months ended June 30, ~~2018.~~2019.

For additional information on volumes, see the "Segment Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018"~~2019" section herein.

Revenues. Total revenues decreased~~$28.5~~ $7.7 million ~~compared to~~during the three months ended June 30, ~~2018~~2020 compared to the prior year period primarily comprised of a ~~$14.5 million decrease in gathering services and related fees and a $13.6~~$7.6 million decrease in natural gas, NGLs and condensate ~~sales.~~sales and a $1.2 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased ~~$14.5~~$1.2 million compared to the three months ended June 30, ~~2018,~~2019, primarily reflecting:

•

a ~~$7.4~~$4.3 million decrease in gathering services and related fees in the ~~Williston~~Piceance Basin ~~primarily reflecting (i) $5.4 million~~related to lower volume throughput due to a lack of drilling and completion activity and natural production declines in ~~lower MVC shortfall revenue attributable to the timing of revenue recognition and (ii) a $3.0 million decrease in gathering services and related fees attributable~~addition to the sale of ~~the Tioga Midstream~~certain assets from our Red Rock Gathering system ~~on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22,~~in December 2019. ~~This was partially offset by an increase relating to higher liquids volume throughput in the Williston Basin due to increased drilling activity.~~

•

a ~~$3.1~~$3.3 million decrease in gathering services and related fees in the ~~Piceance~~Williston Basin ~~relating to lower volume throughput~~ due to lower ~~drilling activity and~~liquids throughput associated with natural production ~~declines.~~declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

•

a ~~$2.8~~$1.6 million decrease in gathering services and related fees in the ~~Utica~~Barnett Shale ~~due to~~primarily reflecting natural production declines ~~on existing wells~~ partially offset by new volumes from well completion activity through the ~~completion of new wells at the end of the fourth~~third quarter ~~of 2018 and in the first half~~ of 2019.

•

a ~~$1.5~~$3.9 million ~~decrease~~increase in gathering services and related fees in the ~~Barnett~~Utica Shale ~~primarily reflecting lower volume throughput and lower gathering rate mix. Also impacting 2019 revenues was the presentation of $1.2 million of gathering services~~ as a ~~reduction to cost~~result of the completion of new wells throughout 2019 and in the first half of 2020, partially offset by natural ~~gas~~production declines on existing wells and ~~NGLs due to the transfer of certain marketing arrangements from Corporate and Other to our DFW Midstream operations.~~temporary production curtailments beginning in June 2020.

•

a ~~$2.2~~$2.1 million ~~decrease~~increase in gathering services and related fees in the ~~Marcellus Shale relating to lower volume throughput~~Permian Basin due to ~~natural production declines.~~higher volume growth from ongoing drilling and completion activity and a more favorable volume and gathering rate mix from customers.

•

a ~~$1.5~~$1.2 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customersand the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production ~~declines.~~declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

•

~~$0.6 million in gathering services and related fees in the Permian Basin (commissioned in the fourth quarter of 2018).~~

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased ~~$13.6~~$7.6 million compared to the three months ended June 30, ~~2018,~~2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $5.5 million decrease in natural gas, NGL and condensate purchases.

Total revenues decreased~~$14.4~~ $34.2 million ~~compared to~~during the six months ended June 30, ~~2018~~2020 compared to the prior year period primarily comprised of ~~an $11.9 million decrease in gathering services and related fees and~~ a ~~$1.8~~$31.8 million decrease in natural gas, NGLs and condensate ~~sales.~~sales and a $4.4 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased ~~$11.9~~$4.4 million compared to the six months ended June 30, ~~2018,~~2019, primarily reflecting:

•

a ~~$5.4~~$9.0 million decrease in gathering services and related fees in the ~~Utica Shale~~Piceance Basin related to lower volume throughput due to a ~~combination~~lack of drilling and completion activity and natural production declines on existing wells together with increased temporary production curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on existing pad sites, partially offset byin addition to the ~~completion~~sale of ~~new wells at the end of the fourth quarter of 2018 and~~certain assets from our Red Rock Gathering system in ~~the first half of~~December 2019.

•

a ~~$4.4~~$5.2 million decrease in gathering services and related fees in the ~~Piceance~~Williston Basin ~~relating to lower volume throughput~~primarily due to lower ~~drilling activity and~~liquids throughput associated with natural production ~~declines.~~declines and, beginning in the second quarter of 2020, temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic. The decrease was also due to a $1.5 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, the 2019 financial results of which are included for the period from January 1, 2019 through March 22, 2019.

•

a ~~$3.8 million decrease in gathering services and related fees in the Marcellus Shale relating to lower volume throughput due to natural production declines.~~

•

~~a $2.1~~$4.1 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting ~~lower volume throughput and lower gathering rate mix.~~natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019. Also impacting ~~2019~~2020 revenues was the presentation ~~of $1.2 million~~ of gathering services as a reduction to cost of natural gas and NGLs due to the ~~transfer~~assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream ~~operations.~~operations that occurred in June 2019, which decreased gathering services and related fees by $1.7 million.

•

a ~~$3.1~~$4.3 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customersand the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production ~~declines.~~

•

~~$1.0 million~~declines and temporary production curtailments associated with a significant reduction in ~~gathering services and related fees~~crude oil prices as a result of a decrease in demand attributable to the ~~Permian Basin (commissioned in the fourth quarter of 2018).~~COVID-19 pandemic.

•

a ~~$0.6~~$4.1 million increase in gathering services and related fees in the ~~Williston~~Permian Basin ~~primarily reflecting higher liquids volume throughput~~ due to ~~increased~~higher volume growth from ongoing drilling ~~activity. This was partially offset by~~and completion activity and a ~~$4.4~~more favorable volume and gathering rate mix from customers.

•

a $3.4 million ~~decrease~~increase in gathering services and related fees ~~attributable to~~in the ~~sale~~Utica Shale as a result of the ~~Tioga Midstream system~~completion of new wells throughout 2019 and in the first half of 2020, and a more favorable volume and gathering rate mix from customers partially offset by natural production declines on ~~March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019.~~existing wells.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased ~~$1.8~~$31.8 million compared to the six months ended June 30, ~~2018,~~2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $29.0 million decrease in natural gas, NGL and condensate purchases.

Costs and Expenses. Total costs and expenses decreased~~$17.7~~ $1.9 million during the three months ended June 30, 2020 compared to the three months ended June 30, ~~2018~~2019, primarily ~~reflecting:~~due to a $5.5 million decrease in natural gas, NGLs and condensate purchases, a $3.2 million decrease in operation and maintenance expense, a $2.8 million increase in depreciation and amortization expense, a $2.2 million increase in general and administrative expense and a $1.1 million increase in transaction costs.

•

a~~$12.8 milliondecrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.~~

•

~~a $3.3 million decrease in general and administrative expense due to a $2.0 million decrease in compensation expense and a $1.3 million decrease in professional service fees.~~

•

a~~$0.7 milliondecrease in operation and maintenance expense.~~

Total costs and expenses ~~increased$42.3~~decreased $70.2 million during the six months ended June 30, 2020 compared to the six months ended June 30, ~~2018~~2019, primarily ~~reflecting:~~due to the impact of: (i) the March 2019 recognition of a $34.9 million and $10.2 million long-lived asset impairment in the DJ Basin and Barnett Shale, respectively, partially offset by the March 2020 recognition of a $3.6 million long-lived asset impairment in the DJ Basin; (ii) a $29.0 million decrease in natural gas, NGLs and condensate purchases; (iii) a $5.6 million decrease in operation and maintenance expense; and (iv) a $4.7 million increase in depreciation and amortization expense.

•

~~the recognition of $34.7 million of certain long-lived asset impairments in the DJ Basin.~~

•

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

•

a~~$1.1 millionincrease in depreciation and amortization, which was primarily driven by the assets placed into service in the Permian Basin.~~

•

a $0.4 million decrease in general and administrative expense primarily due to a $1.7 million decrease in compensation expense and a $1.6 million decrease in professional service fees, partially offset by the recognition of $3.4 million in severance expense relating to our former Chief Executive Officer.

•

a~~$1.3 milliondecrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.~~

•

~~a $1.1 million decrease in operation and maintenance expense.~~

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased ~~$12.8~~$5.5 million and ~~$1.3~~$29.0 million during the three and six months ended June 30, 2020 compared to the three and six months ended June 30, ~~2018,~~2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.

Operation and Maintenance. Operation and maintenance expense decreased $3.2 million for the three months ended June 30, 2020 compared to the three months ended June 30, 2019 primarily due to a $1.4 million decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives and a $0.6 million decrease in remediation expenses.

Operation and maintenance expense decreased $5.6 million for the six months ended June 30, 2020 compared to the six months ended June 30, 2019 primarily due to a $2.7 million decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives, a $1.1 million decrease in property taxes and a $0.8 million decrease in remediation expense.

General and Administrative.General and administrative expense increased $2.2 million for the three months ended June 30, 2020 compared to the three months ended June 30, 2019 primarily due to a $1.3 million increase in professional service fees and a $0.7 million increase in restructuring expenses.

General and ~~$1.1~~administrative expense increased $0.4 million compared to the six months ended June 30, 2019 primarily due to a $4.7 million increase in restructuring expenses and a $1.7 million increase in professional service fees, partially offset by a $6.4 million decrease in compensation expense primarily associated with lower headcount from our cost cutting initiatives.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three and six months ended June 30, 2020 compared to the three and six months ended June 30, ~~2018.~~2019 was primarily due to the acceleration of depreciation on certain Williston Basin assets.

~~General and Administrative~~Transaction Costs.~~General and administrative expense decreased $3.3 million~~ The increase in transaction costs recognized during the three months ended June 30, 2020 compared to the three months ended June 30, ~~2018 due to a $2.0 million decrease in compensation expense and a $1.3 million decrease in professional service fees.~~

~~General and administrative expense decreased $0.4 million compared to the six months ended June 30, 2018~~2019 was primarily due to ~~a $1.7 million~~costs associated with the GP Buy-In Transaction.

The decrease in ~~compensation expense and a $1.6 million decrease in professional service fees, partially offset by the recognition of $3.4 million in severance expense relating to our former Chief Executive Officer.~~

~~Depreciation and Amortization. Depreciation and amortization expense increased $1.1 million compared to the six months ended June 30, 2018, primarily due to the assets placed into service in the Permian Basin.~~

~~Transaction Costs. Transaction~~transaction costs recognized during the six months ended June 30, 2020 compared to the six months ended June 30, 2019 ~~relate~~was due to financial advisory costs ~~primarily associated with the Equity Restructuring.~~incurred in 2019 for a subsidiary equity restructuring that did not occur in 2020.

Interest Expense. ~~Interest~~The decrease in interest expense ~~increased $3.1 million~~for the three and ~~$5.5 million~~six months ended June 30, 2020 compared to the three and six months ended June 30, ~~2018,~~2019, was primarily asdue to a ~~result of~~lower average outstanding balance on the nonrecourse SMPH Term Loan at SMP Holdings that incurs a higher interest rate partially offset by a higher average outstanding balance on the Revolving Credit ~~Facility.~~Facility and the addition of the ECP Loans from the GP Buy-In Transaction.

~~Deferred Purchase Price Obligation~~Gain on early extinguishment of debt. ~~Deferred Purchase Price Obligation recognized~~Following the closing of the GP Buy-In Transaction, inMay 2020, we commenced a debt buyback program on our Senior Notes. Through June 30, 2020, we repurchased $25.8 million of the outstanding $300 million aggregate principal amount of our 5.50% Senior Notes. The gain on early extinguishment of debt for the 5.50% Senior Notes during the three and six months ended June 30, ~~2019 represents~~2020 totaled $9.2 million and is inclusive of the ~~change in present value to Remaining Consideration in connection with~~write off of debt issuance costs of $0.1 million. We also repurchased $106.2 million of the ~~2016 Drop Down (see Note 17 to~~outstanding $500 million aggregate principal amount of our 5.75% Senior Notes. The gain on early extinguishment of debt for the ~~unaudited condensed consolidated financial statements).~~5.75% Senior Notes during the three and six months ended June 30, 2020 totaled $45.1 million and is inclusive of the write off of debt issuance costs of $1.0 million.

For additional information, see the "Segment Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018"~~2019" and "Corporate and Other Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018"~~2019" sections herein.

Segment Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019

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

Utica Shale

Three months ended June 30,

Six months ended June 30,

2019

2018

Percentage
Change

2019

2018

Percentage Change
Average daily throughput (MMcf/d)

260

415

(37%)

273

386

(29%)

	Utica Shale
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		416		260	60%		319		273	17%

Volume throughput ~~declined~~increased compared to the three ~~and six~~ months ended June 30, ~~2018 due to~~2019 as a result of the completion of new wells throughout 2019 and in the first half of 2020, partially offset by natural production declines from existing wells ~~on pad sites connected~~and temporary production curtailments beginning in June 2020.

Volume throughput increased compared to ~~the Summit Utica, partially offset by the completion of new wells at the end of the fourth quarter of 2018 and in the first half of 2019. For~~ the six months ended June 30, 2019 as a result of the completion of new wells throughout 2019 and in the first half of 2020 and a more favorable volume ~~throughput was impacted~~and gathering rate mix from customers, partially offset by ~~an increase in temporary~~natural production ~~curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on~~declines from existing ~~pad sites.~~wells.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale														Utica Shale
	Three months ended June 30,							Six months ended June 30,							Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)														(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,591		$	10,422		(27%)	$	15,086		$	20,463		(26%)	$	11,538		$	7,591		52%	$	18,500		$	15,086		23%
Total revenues		7,591			10,422		(27%)		15,086			20,463		(26%)		11,538			7,591		52%		18,500			15,086		23%
Costs and expenses:
Operation and maintenance		871			1,090		(20%)		2,087			2,309		(10%)		757			871		(13%)		1,698			2,087		(19%)
General and administrative		76			105		(28%)		157			207		(24%)		84			76		11%		172			157		10%
Depreciation and amortization		1,923			2,033		(5%)		3,831			3,886		(1%)		1,920			1,923		(0%)		3,847			3,831		0%
Gain on asset sales, net																(42	)		—		*		(26	)		—		*
Total costs and expenses		2,870			3,228		(11%)		6,075			6,402		(5%)		2,719			2,870		(5%)		5,691			6,075		(6%)
Add:
Depreciation and amortization		1,923			2,033				3,831			3,886				1,920			1,923				3,847			3,831
Adjustments related to capital reimbursement activity		(4	)		(4	)			(9	)		(9	)			(4	)		(4	)			(9	)		(9	)
Gain on asset sales, net																(42	)		—				(26	)		—
Segment adjusted EBITDA	$	6,640		$	9,223		(28%)	$	12,833		$	17,938		(28%)	$	10,693		$	6,640		61%	$	16,621		$	12,833		30%

* Not considered meaningful

Three and ~~Six~~six months ended June 30, ~~2019~~2020. Segment adjusted EBITDA ~~decreased $2.6~~increased $4.1 million and ~~$5.1~~$3.8 million compared to the three and six months ended June 30, ~~2018~~2019 primarily due to the increase in volume throughput ~~declines discussed above.~~previously discussed.

Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity ~~method. We~~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,

2019

2018

Percentage
Change

2019

2018

Percentage Change
Average daily throughput (MMcf/d)

713

727

(2%)

712

749

(5%)

	Ohio Gathering
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		540		713	(24%)		575		712	(19%)

Volume throughput for the Ohio Gathering system decreased compared to the three and six months ended June 30, ~~2018~~2019 as a result of natural production declines on existing wells on the system and temporary production curtailments beginning in the second quarter of 2020, partially offset by the completion of new ~~wells.~~wells throughout 2019.

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

	Ohio Gathering										Ohio Gathering
	Three months ended June 30,					Six months ended June 30,					Three months ended June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change	2020		2019		Percentage Change	2020		2019		Percentage Change
	(Dollars in thousands)										(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	9,939	$	8,935	11%	$	19,149	$	19,412	(1%)	$	7,514	$	9,939	(24%)	$	15,453	$	19,149	(19%)
Segment adjusted EBITDA	$	9,939	$	8,935	11%	$	19,149	$	19,412	(1%)	$	7,514	$	9,939	(24%)	$	15,453	$	19,149	(19%)

Segment adjusted EBITDA for ~~Ohio Gathering increased $1.0~~equity method investees decreased $2.4 million and $3.7 million compared to the three and six months ended June 30, ~~2018~~2019 primarily as a result of the lower ~~expenses.~~

~~Segment adjusted EBITDA for Ohio Gathering decreased $0.3 million compared to the six months ended June 30, 2018.~~volume throughput described above.

Williston Basin. The Polar and Divide, Bison Midstream and Tioga Midstream (through March 22, 2019; refer to Note 1716 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream) systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.

	Williston Basin										Williston Basin
	Three months ended June 30,					Six months ended June 30,					Three months ended June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change	2020		2019		Percentage Change	2020		2019		Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)		11		18	(39%)		13		18	(28%)		14		11	27%		14		13	8%

Aggregate average daily throughput - liquids (Mbbl/d)		94.3		88.9	6%		98.6		86.9	13%		76.0		94.3	(19%)		87.0		98.6	(12%)

Natural gas. Natural gas volume throughput ~~decreased~~increased compared to the three and six months ended June 30, ~~2018~~2019, primarily reflecting the completion of new wells behind the Bison Midstream system in the fourth quarter of 2019 and 2020 partially offset by natural production declines and the sale of Tioga ~~Midstream and operational downtime on the Bison Midstream system.~~Midstream.

Liquids. The ~~increase~~decrease in liquids volume throughput compared to the three and six months ended June 30, ~~2018,~~2019, primarily ~~reflected well completion activity by existing customers on our Polar~~associated with natural production declines and ~~Divide system~~temporary production curtailments associated with a significant reduction in ~~2018 and~~crude oil prices as a result of a decrease in demand attributable to the ~~first half of 2019 as well as the addition of new customers,~~COVID-19 pandemic, partially offset by the ~~sale~~completion of ~~Tioga Midstream~~new wells throughout 2019 and ~~natural production declines.~~2020.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin														Williston Basin
	Three months ended June 30,							Six months ended June 30,							Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)														(Dollars in thousands)
Revenues:
Gathering services and related fees	$	15,685		$	23,106		(32%)	$	41,391		$	40,772		2%	$	12,407		$	15,685		(21%)	$	36,204		$	41,391		(13%)
Natural gas, NGLs and condensate sales		3,768			7,350		(49%)		9,353			15,196		(38%)		3,131			3,768		(17%)		7,455			9,353		(20%)
Other revenues		2,670			2,960		(10%)		5,578			5,872		(5%)		2,776			2,670		4%		5,918			5,578		6%
Total revenues		22,123			33,416		(34%)		56,322			61,840		(9%)		18,314			22,123		(17%)		49,577			56,322		(12%)
Costs and expenses:
Cost of natural gas and NGLs		1,052			4,200		(75%)		3,761			8,808		(57%)		941			1,052		(11%)		2,604			3,761		(31%)
Operation and maintenance		5,706			5,885		(3%)		12,222			12,710		(4%)		5,827			5,706		2%		12,549			12,222		3%
General and administrative		371			597		(38%)		712			1,364		(48%)		492			371		33%		1,030			712		45%
Depreciation and amortization		4,734			5,622		(16%)		10,170			11,231		(9%)		6,487			4,734		37%		12,982			10,170		28%
(Gain) loss on asset sales, net		(175	)		62		*		(1,143	)		62		*
Gain on asset sales, net																(96	)		(175	)	*		(47	)		(1,143	)	*
Long-lived asset impairment		8			—		*		18			—		*		9			8		*		9			18		*
Total costs and expenses		11,696			16,366		(29%)		25,740			34,175		(25%)		13,660			11,696		17%		29,127			25,740		13%
Add:
Depreciation and amortization		4,734			5,622				10,170			11,231				6,487			4,734				12,982			10,170
Adjustments related to MVC shortfall payments		2,081			(3,386	)			(3,468	)		(3,386	)			2,124			2,081				(3,541	)		(3,468	)
Adjustments related to capital reimbursement activity		(425	)		(318	)			(775	)		(572	)			(451	)		(425	)			(934	)		(775	)
(Gain) loss on asset sales, net		(175	)		62				(1,143	)		62
Gain on asset sales, net																(96	)		(175	)			(47	)		(1,143	)
Long-lived asset impairment		8			—				18			—				9			8				9			18
Segment adjusted EBITDA	$	16,650		$	19,030		(13%)	$	35,384		$	35,000		1%	$	12,727		$	16,650		(24%)	$	28,919		$	35,384		(18%)

* Not considered meaningful

Three months ended June 30, ~~2019~~2020. Segment adjusted EBITDA decreased $~~2.4~~3.9 million compared to the three months ended June 30, ~~2018~~2019 primarily due to lower liquids volume throughput on our systems as previously discussed.

Six months ended June 30, 2020. Segment adjusted EBITDAdecreased$6.5 millioncompared to the six months ended June 30, 2019 primarily reflecting:

•

~~$2.3~~a decrease of $0.9 million of segment adjusted EBITDA contributed by the Tioga Midstream system ~~for~~compared to the ~~three months ended June 30, 2018 with no corresponding contribution in the three~~six months ended June 30, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime was due to third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the quarter. This was partially offset by higher liquids volume throughput on our ~~Polar and Divide system due to increased drilling activity in 2018 and in the first half of 2019.~~systems as previously discussed.

~~Six months ended June 30, 2019. Segment adjusted EBITDAincreased$0.4 millioncompared~~Other items to ~~the six months ended June 30, 2018 primarily reflecting:~~note:

•

Higher liquids volume throughput on our Polar and Divide system due to increased drilling activity in 2018 and in the first half of 2019. This was partially offset by a decrease of $3.4 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the six months ended June 30, 2018 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime was due to third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the quarter.

~~Other items to note:~~

•

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

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

DJ Basin

Three months ended June 30,

Six months ended June 30,

2019

2018

Percentage
Change

2019

2018

Percentage Change
Average daily throughput
(MMcf/d)

20

16

25%

21

15

40%

	DJ Basin
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		20		20	-		26		21	24%

Volume throughput increased ~~during~~compared to the ~~three and~~ six months ended June 30, ~~2018, compared to the prior periods,~~2019, primarily as a result of ongoing drilling and completion activity across our service area and a more favorable volume and gathering rate mix from customersand the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production ~~declines.~~declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

Financial data for our DJ Basin reportable segment follows.

	DJ Basin														DJ Basin
	Three months ended June 30,							Six months ended June 30,							Three months ended June 30,						Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change	2020		2019			Percentage Change	2020		2019			Percentage Change
	(Dollars in thousands)														(Dollars in thousands)
Revenues:
Gathering services and related fees	$	4,021		$	2,509		60%	$	7,745		$	4,688		65%	$	5,228	$	4,021		30%	$	12,083	$	7,745		56%
Natural gas, NGLs and condensate sales		101			79		28%		186			159		17%		71		101		(30%)		141		186		(24%)
Other revenues		1,034			969		7%		2,041			1,726		18%		993		1,034		(4%)		2,027		2,041		(1%)
Total revenues		5,156			3,557		45%		9,972			6,573		52%		6,292		5,156		22%		14,251		9,972		43%
Costs and expenses:
Cost of natural gas and NGLs		—			7		*		10			14		(29%)		2		—		*		11		10		*
Operation and maintenance		2,028			1,630		24%		3,877			3,106		25%		2,354		2,028		16%		4,870		3,877		26%
General and administrative		60			835		(93%)		132			957		(86%)		141		60		135%		223		132		69%
Depreciation and amortization		464			784		(41%)		1,263			1,565		(19%)		1,502		464		224%		3,029		1,263		140%
Loss on asset sales, net																20		—		*		20		—		*
Long-lived asset impairment		38			—		*		34,759			—		*		57		38		*		3,692		34,759		*
Total costs and expenses		2,590			3,256		(20%)		40,041			5,642		610%		4,076		2,590		57%		11,845		40,041		(70%)
Add:
Depreciation and amortization		464			784				1,263			1,565				1,502		464				3,029		1,263
Adjustments related to capital reimbursement activity		(252	)		(126	)			(464	)		(216	)			544		(252	)			1,103		(464	)
Loss on asset sales, net																20		—				20		—
Long-lived asset impairment		38			—				34,759			—				57		38				3,692		34,759
Segment adjusted EBITDA	$	2,816		$	959		194%	$	5,489		$	2,280		141%	$	4,339	$	2,816		54%	$	10,250	$	5,489		87%

* Not considered meaningful

Three months ended June 30, ~~2019~~2020. Segment adjusted EBITDA increased $~~1.9~~1.5 million compared to the three months ended June 30, ~~2018,~~2019, primarily reflecting:

•

~~A $1.5~~a $1.2 million increase in gathering services and related fees primarily ~~as a result of volume growth from ongoing drilling and completion activity and~~due a more favorable volume and gathering rate mix from customersand the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production ~~declines.~~declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

Six months ended June 30, 2020. Segment adjusted EBITDA increased$4.8 millioncompared to the six months ended June 30, 2019, primarily reflecting:

•

a ~~$0.8 million decrease in general and administrative expense primarily due to lower professional service fees.~~

•

~~a $0.4 million increase in operation and maintenance expense primarily due to higher costs to support increased volumes.~~

~~Six months ended June 30, 2019. Segment adjusted EBITDA increased$3.2 millioncompared to the six months ended June 30, 2018, primarily reflecting:~~

•

~~A $3.1~~$4.3 million increase in gathering services and related fees primarily ~~as a result of volume growth from ongoing drilling and completion activity and a more favorable volume mix from customers, partially offset by natural production declines.~~

•

~~a $0.8 million decrease in general and administrative expense primarily~~ due to ~~lower professional service fees.~~

•

~~a $0.8 million~~the increase in ~~operation and maintenance expense primarily due to higher costs to support~~ volume ~~growth.~~throughput discussed above.

Other items to note:

•

During the ~~quarter~~six months ended ~~March 31,~~June 30, 2020 and 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the unaudited condensed consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the ~~three and~~ six months ended June 30, 2020 and 2019.

Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment ~~which commenced operations late in the fourth quarter of 2018.~~follows.

	Permian Basin
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		32		17	88%		33		16	106%

~~Average daily volume~~Volume throughput ~~during~~increased compared to the three and six months ended June 30, 2019, ~~totaled 17 MMcf/d~~primarily as a result of ongoing drilling and ~~16 MMcf/d, respectively.~~completion activity across our service area.

Financial data for our Permian Basin reportable segment follows.

	Permian Basin
	Three months ended June 30,							Six months ended June 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change
	(In thousands)
Revenues:
Gathering services and related fees	$	2,711		$	586		363%	$	5,022		$	952		428%
Natural gas, NGLs and condensate sales		4,222			2,406		75%		8,734			6,627		32%
Other revenues		126			49		157%		313			81		286%
Total revenues		7,059			3,041		132%		14,069			7,660		84%
Costs and expenses:
Cost of natural gas and NGLs		3,691			1,882		96%		7,840			6,127		28%
Operation and maintenance		1,456			1,733		(16%)		2,643			2,624		1%
General and administrative		84			82		2%		177			115		54%
Depreciation and amortization		1,387			1,163		19%		2,732			2,235		22%
Gain on asset sales, net		(17	)		(120	)	*		(13	)		(120	)	*
Long-lived asset impairment		—			8		*		182			8		*
Total costs and expenses		6,601			4,748		39%		13,561			10,989		23%
Add:
Depreciation and amortization		1,387			1,163				2,732			2,235
Gain on asset sales, net		(17	)		(120	)			(13	)		(120	)
Long-lived asset impairment		—			8				182			8
Segment adjusted EBITDA	$	1,828		$	(656	)	*	$	3,409		$	(1,206	)	*

Permian Basin

Three months ended June 30, 2019

Six months ended June 30, 2019

(In thousands)

Revenues:

Gathering services and related fees

$
586

$
952

Natural gas, NGLs and condensate sales

2,406

6,627

Other revenues

49

81

Total revenues

3,041

7,660

Costs and expenses:

Cost of natural gas and NGLs

1,882

6,127

Operation and maintenance

1,733

2,624

General and administrative

82

115

Depreciation and amortization

1,163

2,235

Gain on asset sales, net

(120
)

(120
)
Long-lived asset impairment

8

8

Total costs and expenses

4,748

10,989

Add:

Depreciation and amortization

1,163

2,235

Gain on asset sales, net

(120
)

(120
)
Long-lived asset impairment

8

8

Segment adjusted EBITDA

$
(656
)

$
(1,206
)

*Not considered meaningful

Three months ended June 30, 2020. Segment adjusted EBITDA increased $2.5 million compared to the three months ended June 30, 2019, primarily reflecting a $2.1 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity and a more favorable volume and gathering rate mix from customers.

Six months ended June 30, ~~2019~~2020. Segment adjusted EBITDA ~~totaled ($0.7)~~increased $4.6 million ~~and ($1.2) million for~~compared to the ~~three and~~ six months ended June 30, 2019, ~~respectively,~~ primarily reflecting ~~fixed operating costs associated with commissioning~~a $4.1 million increase in gathering services and ~~operating the Lane processing plant~~related fees as a result of volume growth from ongoing drilling and ~~certain inefficiencies~~completion activity and ~~higher fuel costs associated with lower plant utilization~~a more favorable volume and ~~initial production volumes.~~gathering rate mix from customers.

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

Piceance Basin

Three months ended June 30,

Six months ended June 30,

2019

2018

Percentage
Change

2019

2018

Percentage
Change
Aggregate average daily throughput
(MMcf/d)

462

560

(18%)

473

562

(16%)

	Piceance Basin
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Aggregate average daily throughput (MMcf/d)		367		462	(21%)		375		473	(21%)

Volume throughput decreased compared to the three and six months ended June 30, ~~2018, primarily~~2019, as a result of a natural production ~~declines and operational downtime, partially offset by drilling and completion activity that occurred across our service area through the third quarter of 2018.~~declines.

Financial data for our Piceance Basin reportable segment follows.

	Piceance Basin														Piceance Basin
	Three months ended June 30,							Six months ended June 30,							Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)														(Dollars in thousands)
Revenues:
Gathering services and related fees	$	30,555		$	33,661		(9%)	$	62,395		$	66,776		(7%)	$	26,222		$	30,555		(14%)	$	53,411		$	62,395		(14%)
Natural gas, NGLs and condensate sales		2,104			4,596		(54%)		4,406			8,841		(50%)		401			2,104		(81%)		1,404			4,406		(68%)
Other revenues		945			1,178		(20%)		2,083			2,389		(13%)		1,096			945		16%		2,161			2,083		4%
Total revenues		33,604			39,435		(15%)		68,884			78,006		(12%)		27,719			33,604		(18%)		56,976			68,884		(17%)
Costs and expenses:
Cost of natural gas and NGLs		1,280			2,952		(57%)		2,753			5,513		(50%)		320			1,280		(75%)		777			2,753		(72%)
Operation and maintenance		7,108			9,538		(25%)		14,407			17,382		(17%)		5,267			7,108		(26%)		10,205			14,407		(29%)
General and administrative		302			383		(21%)		596			709		(16%)		276			302		(9%)		561			596		(6%)
Depreciation and amortization		11,810			11,666		1%		23,601			23,440		1%		11,306			11,810		(4%)		22,604			23,601		(4%)
Loss on asset sales, net		3			—		*		3			—		*
(Gain) loss on asset sales, net																(83	)		3		*		(96	)		3		*
Total costs and expenses		20,503			24,539		(16%)		41,360			47,044		(12%)		17,086			20,503		(17%)		34,051			41,360		(18%)
Add:
Depreciation and amortization		11,810			11,666				23,601			23,440				11,306			11,810				22,604			23,601
Loss on asset sales, net		3			—				3			—
Adjustments related to MVC shortfall payments		—			(93	)			(103	)		(93	)			167			—				390			(103	)
Adjustments related to capital reimbursement activity		(330	)		245				(442	)		319				(289	)		(330	)			(532	)		(442	)
(Gain) loss on asset sales, net																(83	)		3				(96	)		3
Segment adjusted EBITDA	$	24,584		$	26,714		(8%)	$	50,583		$	54,628		(7%)	$	21,734		$	24,584		(12%)	$	45,291		$	50,583		(10%)

*Not considered meaningful

Three months ended June 30, ~~2019~~2020. Segment adjusted EBITDA decreased ~~$2.1~~$2.9 million compared to the three months ended June 30, ~~2018,~~2019, primarily reflecting:

•

a ~~$3.1~~$4.3 million decrease in gathering services and related fees as a result of natural production ~~declines and operational downtime.~~declines.

•

a ~~$0.8 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of~~ ~~lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate~~.

•

~~a $2.4~~$1.8 million decrease in operation and maintenance expense primarily due to ~~a $1.6 million reduction in planned compressor overhaul maintenance costs and $0.5~~$1.0 million in lower compensation ~~expense.~~expense associated with lower headcount from our cost cutting initiatives.

Other items to note:

•

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

Six months ended June 30, ~~2019~~2020. Segment adjusted EBITDA decreased ~~$4.0~~$5.3 million compared to the six months ended June 30, ~~2018,~~2019, primarily reflecting:

•

a ~~$4.4~~$9.0 million decrease in gathering services and related fees as a result of natural production ~~declines and operational downtime.~~declines.

•

a ~~$1.7 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of~~ ~~lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate~~.

•

~~a $3.0~~$4.2 million decrease in operation and maintenance expense primarily due to ~~a $1.8 million reduction in planned compressor overhaul maintenance costs, $0.7~~$2.2 million in lower compensation expense associated with lower headcount from our cost cutting initiatives and ~~$0.3~~a $0.7 million decrease in ~~lower~~ property taxes.

Other items to note:

•

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,

2019

2018

Percentage
Change

2019

2018

Percentage
Change
Average daily throughput (MMcf/d)

251

264

(5%)

260

263

(1%)

	Barnett Shale
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		203		251	(19%)		218		260	(16%)

Volume throughput ~~declined~~decreased compared to the three and six months ended June 30, ~~2018~~2019 reflecting natural production declines, partially offset by new volumes from well completion activity ~~during~~through the ~~first~~third quarter of 2019.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale														Barnett Shale
	Three months ended June 30,							Six months ended June 30,							Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)														(Dollars in thousands)
Revenues:
Gathering services and related fees	$	11,428		$	14,080		(19%)	$	24,453		$	27,717		(12%)	$	9,877		$	11,428		(14%)	$	20,320		$	24,453		(17%)
Natural gas, NGLs and condensate sales		6,273			381		1546%		6,877			926		643%		2,858			6,273		(54%)		6,729			6,877		(2%)
Other revenues (1)		1,646			1,694		(3%)		3,302			3,682		(10%)		1,778			1,646		8%		3,038			3,302		(8%)
Total revenues		19,347			16,155		20%		34,632			32,325		7%		14,513			19,347		(25%)		30,087			34,632		(13%)
Costs and expenses:
Cost of natural gas and NGLs		4,574			—		*		4,574			—		*		1,134			4,574		(75%)		3,081			4,574		(33%)
Operation and maintenance		5,116			4,942		4%		10,614			11,115		(5%)		4,564			5,116		(11%)		9,259			10,614		(13%)
General and administrative		238			235		1%		466			546		(15%)		513			238		116%		891			466		91%
Depreciation and amortization		3,804			3,909		(3%)		7,745			7,817		(1%)		3,788			3,804		(0%)		7,585			7,745		(2%)
Loss (gain) on asset sales, net		—			—		*		7			(74	)	(109%)
(Gain) loss on asset sales, net																(42	)		—		*		17			7		*
Long-lived asset impairment		16			—		*		10,236			—		*		—			16		*		4			10,236		*
Total costs and expenses		13,748			9,086		51%		33,642			19,404		73%		9,957			13,748		(28%)		20,837			33,642		(38%)
Add:
Depreciation and amortization		4,167			3,759				8,497			7,516				4,023			4,167				8,055			8,497
Adjustments related to MVC shortfall payments		1,452			(63	)			2,905			(63	)			—			1,452				—			2,905
Adjustments related to capital reimbursement activity		(26	)		328				(53	)		652				(27	)		(26	)			(56	)		(53	)
Loss (gain) on asset sales, net		—			—				7			(74	)
(Gain) loss on asset sales, net																(42	)		—				17			7
Long-lived asset impairment		16			—				10,236			—				—			16				4			10,236
Segment adjusted EBITDA	$	11,208		$	11,093		1%	$	22,582		$	20,952		8%	$	8,510		$	11,208		(24%)	$	17,270		$	22,582		(24%)

*Not considered meaningful

(1) Includes the amortization expense associated with our favorable ~~and unfavorable (in 2018)~~ gas gathering contracts as reported in ~~other~~Other revenues.

Three months ended June 30, ~~2019~~2020. Segment adjusted EBITDA ~~was flat~~ decreased$2.7 millioncompared to the three months ended June 30, ~~2018~~2019 primarily reflecting:

•

a $1.5 million ~~increase~~decrease in adjustments related to MVC shortfall payments attributable to an ~~expected cumulative shortfall payment from~~MVC that expired in 2019 and a ~~certain customer due in the fourth quarter of 2019, offset by a $1.5~~$1.4 million decrease in ~~gathering services~~total revenues less cost of natural gas and ~~related fees~~NGLs which primarily ~~reflecting~~reflects lower volume ~~throughput and lower gathering rate mix.~~ throughput.

Other items to note:

•

Also impacting ~~2019~~total revenues and cost of natural gas and NGLs for the three months ended June 30, 2020, was the presentation of ~~$1.2 million of~~certain gathering services as a reduction to cost of natural gas and NGLs ~~due to~~and the ~~transfer~~assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream ~~operations.~~operations that occurred in June 2019.

Six months ended June 30, ~~2019~~2020. Segment adjusted EBITDA ~~increased~~decreased $~~1.6~~5.3 million compared to the six months ended June 30, ~~2018~~2019 primarily reflecting:

•

a $2.9 million ~~increase~~decrease in adjustments related to MVC shortfall payments attributable to an ~~expected cumulative shortfall payment from~~MVC that expired in 2019 and a ~~certain customer due in the fourth quarter of 2019, partially offset by a $2.1~~$3.1 million decrease in ~~gathering services and related fees primarily reflecting lower volume throughput and lower gathering rate mix. Also impacting 2019~~total revenues ~~was the presentation of $1.2 million of gathering services as a reduction to~~less cost of natural gas and NGLs ~~due to the transfer of certain marketing arrangements from Corporate and Other to our DFW Midstream operations.~~which primarily reflects lower volume throughput.

•

a ~~$0.5~~$1.4 milliondecreasein various operation and maintenance expenses.

Other items to note:

•

In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 5 to the unaudited condensed consolidated financial statements). The noncash impairment expense had no impact on segment adjusted EBITDA for the ~~three and~~ six months ended June 30, 2019.

•

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

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

Marcellus Shale

Three months ended June 30,

Six months ended June 30,

2019

2018

Percentage
Change

2019

2018

Percentage
Change
Average daily throughput (MMcf/d)

347

524

(34%)

363

523

(31%)

	Marcellus Shale
	Three months ended June 30,					Six months ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change
Average daily throughput (MMcf/d)		339		347	(2%)		351		363	(3%)

Volume throughput decreased compared to the three and six months ended June 30, ~~2018~~2019 primarily due to natural production ~~declines.~~declines partially offset by additional drilling and completion activities in the third quarter of 2019.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale														Marcellus Shale
	Three months ended June 30,							Six months ended June 30,							Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change	2020			2019			Percentage Change	2020			2019			Percentage Change
	(Dollars in thousands)														(Dollars in thousands)
Revenues:
Gathering services and related fees	$	5,897		$	8,050		(27%)	$	12,094		$	15,875		(24%)	$	5,928		$	5,897		1%	$	12,163		$	12,094		1%
Total revenues		5,897			8,050		(27%)		12,094			15,875		(24%)		5,928			5,897		1%		12,163			12,094		1%
Costs and expenses:
Operation and maintenance		1,155			1,400		(18%)		2,109			2,426		(13%)		933			1,155		(19%)		1,746			2,109		(17%)
General and administrative		97			97		*		189			211		(10%)		97			97		-		190			189		1%
Depreciation and amortization		2,286			2,274		1%		4,569			4,546		1%		2,300			2,286		1%		4,600			4,569		1%
Total costs and expenses		3,538			3,771		(6%)		6,867			7,183		(4%)		3,330			3,538		(6%)		6,536			6,867		(5%)
Add:
Depreciation and amortization		2,286			2,274				4,569			4,546				2,300			2,286				4,600			4,569
Adjustments related to capital reimbursement activity		(10	)		(10	)			(19	)		(19	)			(10	)		(10	)			(19	)		(19	)
Segment adjusted EBITDA	$	4,635		$	6,543		(29%)	$	9,777		$	13,219		(26%)	$	4,888		$	4,635		5%	$	10,208		$	9,777		4%

*Not considered meaningful

Three ~~months ended June 30, 2019. Segment adjusted EBITDA decreased $1.9 million compared to the three months ended June 30, 2018 primarily reflecting:~~

•

~~a $2.2 million decrease in gathering services~~ and ~~related fees as a result of volume declines.~~

•

~~a $0.2 million decrease in operation and maintenance expense.~~

~~Six months ended June 30, 2019. Segment adjusted EBITDA decreased $3.4 million compared to the~~ six months ended June 30, ~~2018 primarily reflecting:~~2020. Segment adjusted EBITDA increased $0.3 million and $0.4 million

•

~~a $3.8 million decrease in gathering services and related fees as a result of volume declines.~~

•

~~a $0.3 million decrease in operation and maintenance expense.~~

compared to the three and six months ended June 30, 2019.

Corporate and Other Overview for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019

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

expense.

	Corporate and Other										Corporate and Other
	Three months ended June 30,					Six months ended June 30,					Three months ended June 30,						Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change	2020			2019		Percentage Change	2020			2019		Percentage Change
	(Dollars in thousands)										(Dollars in thousands)
Revenues:
Total revenues		2,927		17,148	(83%)	$	26,444	$	30,421	(13%)		644			2,927	(78%)	$	1,287		$	26,444	(95%)
Costs and expenses:
Cost of natural gas and NGLs		2,783		17,225	(84%)		26,105		30,334	(14%)		—			2,783	*		—			26,105	*
General and administrative		8,988		11,233	(20%)		25,128		23,933	5%		11,099			9,338	19%		26,103			26,582	(2%)
Transaction costs		—		—	*		950		—	*		1,207			96	*		1,218			2,433	*
Interest expense		17,941		14,837	21%		35,468		29,959	18%		21,990			22,343	(2%)		45,818			45,085	2%
Deferred Purchase Price Obligation		3,712		69,305	*		8,139		90,963	*
Gain on early extinguishment of debt												(54,235	)		—	*		(54,235	)		—	*

* Not considered meaningful

Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of ~~$14.2~~$2.3 million and ~~$4.0~~$25.2 million ~~for~~compared to the three and six months ended June 30, 2019, respectively, was attributable to lower natural gas, NGL and crude oil marketing activity.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of ~~$14.4~~$2.8 million and ~~$4.2~~$26.1 million ~~for~~compared to the three and six months ended June 30, 2019, respectively, was attributable to lower marketing activity.

General and Administrative. General and administrative expense ~~decreased $2.2~~increased $1.8 million compared to the three months ended June 30, ~~2018~~2019 primarily due to a ~~$2.0~~$0.8 million ~~decrease in compensation expense and a $0.4 million decrease~~increase in professional service ~~fees.~~fees and a $0.7 million increase in restructuring expenses.

General and administrative expense ~~increased $1.2~~decreased $0.5 million compared to the six months ended June 30, ~~2018~~ 2019~~primarily due to the recognition of $3.4 million in severance expense relating to our former Chief Executive Officer partially offset by a $1.7 million decrease in compensation expense.~~.

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

The decrease in transaction costs recognized during the six months ended June 30, 2020 compared to the six months ended June 30, 2019 ~~relate~~was due to financial advisory costs ~~primarily associated with the Equity Restructuring.~~incurred in 2019 for a subsidiary equity restructuring that did not occur in 2020.

Interest Expense. Interest expense ~~increased $3.1~~decreased $1.2 million and ~~$5.5~~$0.2 million compared to the three and six months ended June 30, ~~2018, respectively,~~ 2019 primarily asdue to a ~~result of~~lower average outstanding balance on the nonrecourse SMPH Term Loan at SMP Holdings that incurs a higher interest rate partially offset by a higher average outstanding balance on the Revolving Credit Facility. and the addition of the ECP Loans from the GP Buy-In Transaction.

~~Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during~~Summarized Financial Information

On March 2, 2020, the ~~three~~SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and ~~six months ended June 30, 2019 represents~~Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities (“Release 33-10762”), that amends the ~~change in present value~~disclosure requirements related to ~~Remaining Consideration in connection~~certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate.

Under Release 33-10762, an SEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the ~~2016 Drop Down~~parent company and its security is either (a) co-issued jointly and severally with the parent company’s security or (b) the subsidiary issuer’s security is fully and unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees.

The rules become effective January 4, 2021, with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 179 to the unaudited condensed consolidated financial statements).SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762 as of and for the six months ended June 30, 2020.

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

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

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

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

	June 30, 2020
	SMLP		Obligor Group
	(In thousands)
Assets
Current assets	$	3,215	$	117,637
Noncurrent assets		11,007		2,338,460

Liabilities
Current liabilities	$	10,862	$	92,822
Noncurrent liabilities		5,945		1,443,485

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

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

Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities' results would have been had they operated on a stand-alone basis.

Summarized statements of operations for the six months ended June 30, 2020 and for the year ended December 31, 2019 follow.

	Six months ended June 30, 2020
	SMLP			Obligor Group
	(In thousands)
Total revenues	$	—		$	196,910
Total costs and expenses		3,944			146,671
(Loss) income before income taxes and income from equity method investees		(3,775	)		65,489
Income from equity method investees		—			7,252
Net (loss) income		(3,696	)		72,741

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

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

Liquidity and Capital Resources

~~Based~~On May 3, 2020, we suspended distributions to holders of our common units and suspended payment of distributions to holders of our Series A Preferred Units commencing with respect to the quarter ending March 31, 2020 to enable us to retain an incremental approximately $76 million of cash in the business annually, which we plan to use to de-lever the balance sheet, enhance liquidity and increase financial flexibility. The unpaid distributions on the ~~terms of our Partnership Agreement, we expect that we~~Series A Preferred Units will ~~distribute~~continue to ~~our unitholders most of the cash generated by our operations. As a result, we~~accrue. We expect to fund future capital expenditures ~~from~~with cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt, preferred equity and ~~preferred~~ equity securities and proceeds from potential asset divestitures.

On June 18, 2020, the Partnership commenced the Exchange Offer. The Exchange Offer expired on July 28, 2020. As a result of the Exchange Offer, the Partnership exchanged 62,816 Series A Preferred Units at a ratio of 200 common units per Series A Preferred Unit for a total of 12,563,200 common units, subject to applicable withholding taxes. Upon completion of the Exchange Offer, 237,184 Series A Preferred Units were not tendered and remain outstanding as of the completion of the Exchange Offer. Holders of Series A Preferred Units who did not tender into this Exchange Offer will retain their Series A Preferred Units and all the preferences and rights thereunder.

We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our liquidity and capital resources. Considering the current commodity price backdrop and COVID-19 pandemic, we have collaborated extensively with our customer base over the past several months. Given further deterioration of market conditions since March and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. For example, in the Utica Shale, a customer has recently curtailed in excess of 150 MMcf/d of production which the Partnership now expects will remain offline awaiting more favorable natural gas prices in late 2020 and into 2021, and we recently amended gathering contracts with two key Williston Basin customers to extend the terms of the gathering agreement acreage dedications, in exchange for a modest gathering fee concession. Accordingly, given reduced producer activity across our footprint, we expect 2020 total capital expenditures to range from $30 million to $50 million.

We are currently in compliance with all covenants contained in our Revolving Credit Facility, Senior Notes, SMPH Term Loan and ECP Loans, and at June 30, 2020, SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) were 4.9 to 1.0 and 2.5 to 1.0, respectively, relative to maximum threshold limits of 5.50 to 1.0 and 3.75 to 1.0. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on access to capital markets to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows.

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

Capital Markets Activity

We had no capital markets activity during the six months ended June 30, ~~2019.~~2020. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the ~~2018~~2019 Annual Report.

~~Debt~~

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit ~~Facility.~~Facility that matures in May 2022. As of June 30, ~~2019,~~2020, the outstanding balance of the Revolving Credit Facility was ~~$573.0~~$733.0 million and the unused portion totaled ~~$667.9~~$512.9 million, after giving effect to the issuance thereunder of a ~~$9.1~~$4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of June 30, 2020 was approximately $191 million. There were no defaults or events of default during the six months ended June 30, ~~2019,~~2020, and, as of June 30, ~~2019,~~2020, we were in compliance with the financial

covenants in the Revolving Credit Facility. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the Agreement, and the transactions contemplated thereby, and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility. See Notes 109 and 1615 to the unaudited condensed consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the ~~$9.1~~$4.1 million letter of credit, respectively. ~~A copy of the amendment is filed as Exhibit 10.2 to this report on Form 10-Q.~~

Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the six months ended June 30, ~~2019~~2020 on either series of senior notes.

Debt Repurchases.Following the closing of the GP Buy-In Transaction, in May 2020, we commenced a debt buyback program on our Senior Notes, which is ongoing. The following table summarizes repurchases of Senior Notes in 2020 through June 30, 2020.

	Three and six months ended June 30, 2020
	(In thousands)
Senior Secured Notes
5.5% Senior Notes repurchased	$	25,776
Cash paid on 5.5% Senior Notes (excluding payments of accrued interest)		16,476
Write-off of debt issuance costs		(116	)
Gain on early extinguishment of debt (1)	$	9,184

5.75% Senior Notes repurchased	$	106,235
Cash paid on 5.75% Senior Notes (excluding payments of accrued interest)		60,231
Write-off of debt issuance costs		(953	)
Gain on early extinguishment of debt (1)	$	45,051

(1) Gain on the early extinguishment of debt for the Senior Notes during the six months ended June 30, 2020 is reported within Gain on early extinguishment of debt, net within our unaudited condensed consolidated statements of operations.

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

For additional information on our long-term debt, see Note 109 to the unaudited condensed consolidated financial statements.

LIBOR Transition

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

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

~~Deferred Purchase Price Obligation~~

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Note 17 to the unaudited condensed consolidated financial statements and the “Contractual Obligations Update” section below).

Cash Flows

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

	Six months ended June 30,						Six months ended June 30,
	2019			2018			2020			2019
	(In thousands)						(In thousands)
Net cash provided by operating activities	$	96,246		$	110,049		$	105,371		$	84,574
Net cash used in investing activities		(20,160	)		(90,204	)		(106,937	)		(20,160	)
Net cash used in financing activities		(79,896	)		(13,063	)
Net change in cash and cash equivalents	$	(3,810	)	$	6,782
Net cash provided by (used in) financing activities								6,263			(74,945	)
Net change in cash, cash equivalents and restricted cash							$	4,697		$	(10,531	)

Operating activities. Cash flows from operating activities for the six months ended June 30, ~~2019~~2020 primarily reflected:

•

a ~~$6.5~~$7.0 million increase in accounts receivable related to the timing of invoicing and cash ~~interest payments;~~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, 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.

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

•

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

•

$111.1 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $50.4 million, Summit Permian of $28.2 million, Corporate and Other, which includes $15.4 million of capital expenditures relating to the Project, and the Williston Basin of $14.2 million;

•

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

•

$5.9 million for an investment in an equity method investee.

Cash flows used in investing activities during the six months ended June 30, 2018 primarily reflected $90.4 million of capital expenditures attributable to the development of the Summit Permian system as well as the continued development in the DJ Basin.

Financing activities. Cash flows used in financing activities during the six months ended June 30, ~~2019~~2020 primarily reflected:

•

$~~83.3~~56.0 million of ~~distributions;~~ net borrowings under our Revolving Credit Facility;

•

$~~107.0~~48.7 million of net proceeds from the issuance of Subsidiary Series A Preferred Units;

•

$35.0 million of net borrowings under ~~our Revolving Credit Facility;~~ECP Loans;

•

$76.7 million repurchase of Senior Notes;

•

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

•

$~~100.0~~6.0 million ~~payment on the Deferred Purchase Price Obligation.~~of distributionsto noncontrolling interest SMLP unitholders.

Cash flows used in financing activities during the six months ended June 30, ~~2018~~2019 primarily reflected:

•

$~~95.0~~83.3 million of ~~net borrowings under our Revolving Credit Facility;~~distributions; and

•

$~~104.5~~107.0 million of ~~distributions.~~net borrowings under our Revolving Credit Facility.

Contractual Obligations Update

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

~~For additional information, see Note 17~~We are leading the development, permitting and construction of the Double E Project and will operate the pipeline upon its commission. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the ~~unaudited condensed consolidated financial statements.~~Double E Project will total approximately $315.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the required regulatory approvals (including the Federal Energy Regulatory Commission’s issuance of the certificate required for us to pursue the Double E Project) and no material delays in construction, we expect that the Double E Project will be placed into service in the third quarter of 2021.

Capital Requirements

Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our ~~partnership agreement~~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, ~~2019,~~2020, cash paid for capital expenditures totaled $~~111.1~~27.4 million (see Note 4 to the unaudited condensed consolidated financial statements) which included~~$7.0~~ $7.5 million of maintenance capital expenditures. For the six months ended June 30, ~~2019,~~2020, there were no contributions to Ohio Gathering and we contributed ~~$5.3~~$79.7 million to Double E (see Note 8 to the unaudited condensed consolidated financial statements).

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

Considering the current commodity price backdrop and COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to ~~require significant expenditures~~advance our financing plans for our equity interest in Double E, which we intend to be credit neutral to SMLP. We are currently targeting a financing structure that limits cash investments made by ~~us. Consequently,~~us during 2020, and which shifts a substantial majority of our ~~ability~~Double E capital commitments to ~~develop~~third parties. On December 24, 2019, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco to TPG for net proceeds of $27.3 million.

During the six months ended June 30, 2020, we issued an additional 50,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $48.7 million (after deducting underwriting discounts and ~~maintain sources~~offering expenses) to fund Summit’s share of ~~funds to meet our~~ capital ~~requirements is critical to our ability to meet our growth objectives.~~ expenses associated with the Double E Project.

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

~~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, to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and financial support from our Sponsor and/or access to debt or equity capital markets, will be adequate to finance our growth objectives for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.sources.

Credit and Counterparty Concentration Risks

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

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

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

For additional information, see Notes 4, 9, 11 and 1116 to the unaudited condensed consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the six months ended June 30, ~~2019.~~2020.

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no changes to our significant accounting policies since December 31, ~~2018 except for the adoption of Topic 842 (see Note 2 to the unaudited condensed consolidated financial statements).~~2019.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us ~~our subsidiaries, Summit Investments~~ or our ~~Sponsor,~~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:

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our ability to grow ~~or maintain,~~ our ~~current rate of~~ cash distributions;

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

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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;

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

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

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

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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;

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

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the ability to attract and retain key management personnel;

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

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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;

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

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

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

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

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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;

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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;

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

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

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~~changes in tax status;~~the ability to meet obligations under the SMPH Term Loan;

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~~the effects of litigation;~~changes in tax status;

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~~changes in general economic conditions; and~~the effects of litigation;

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changes in general economic conditions; and

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certain factors discussed elsewhere in this report.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units, preferred units and senior notes.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our debt portfolio. As of June 30, ~~2019,~~2020, we had ~~$800.0~~approximately $668.0 million principal of fixed-rate Senior Notes, ~~and $573.0~~$35 million principal of fixed rate ECP Loans, $733.0 million outstanding under our variable rate Revolving Credit Facility and $155.2 million principal of variable rate debt on the SMPH Term Loan (see Note 109 to the unaudited condensed consolidated financial statements). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, ~~2018.~~2019. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the ~~2018~~2019 Annual Report.

Commodity Price Risk

We currently generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, ~~many~~certain of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. Our gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. Our gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the ~~Henry Hub Index and/or the~~ Atmos Zone 3 Index. By basing the power prices on ~~an index~~a system and basin-relevant market, like the Henry Hub Index, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. Our current commodity price risk exposure has not changed materially since December 31, ~~2018.~~2019. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the ~~2018~~2019 Annual Report.

Item 4. Controls and Procedures.

Under the direction of our General Partner's Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of June 30, ~~2019~~2020 and (ii) no change in internal control over financial reporting occurred during the quarter ended June 30, ~~2019,~~2020, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental ~~proceedings, except as noted below.~~proceedings. In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted in Note 1615 to our unaudited condensed consolidated financial statements ~~“Commitments~~“Leases, Commitments and Contingencies” and in the ~~2018~~2019 Annual Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of ~~(i)~~ the ~~2018~~2019 Annual Report and ~~(ii)~~in the ~~Quarterly Report~~Item 1A. Risk Factors of our quarterly report on Form 10-Q for the ~~quarterly period~~three months ended March 31, ~~2019~~2020, as filed with the SEC on May ~~10, 2019~~8, 2020 (the “First Quarter Quarterly 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 update, and should be considered in addition to, the risk factors previously disclosed by us in our 2019 Annual Report and the First Quarter Quarterly Report.

Risks Relating to COVID-19

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

The ongoing coronavirus (COVID-19) outbreak continues to be a rapidly evolving situation. As of July 27, 2020, the CDC had recorded over 4.1 million cases in the United States and over 145,000 deaths, and the pandemic has resulted in a massive increase in the U.S. unemployment rate. The pandemic has resulted in widespread adverse impacts on the global economy and on our business, including our customers, employees, supply chain, and distribution network. We are currently unable to predict the ultimate impact that it may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

In the midst of the ongoing COVID-19 pandemic, oil prices declined significantly due to potential increases in supply emanating from a disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. For example, we have experienced a $5.2 million decrease in gathering services and related fees in the Williston Basin primarily due to lower liquids throughput associated in part with a decrease in demand resulting from the COVID-19 pandemic. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, there is no assurance that the agreement will continue to be observed by its parties, and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Such responses could cause our pipelines and storage tanks to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows. At this point, we cannot accurately predict what effects current market conditions due to the COVID-19 pandemic and failed OPEC negotiations will have on our business, which will depend on, among other factors, the ultimate geographic spread of the virus, the duration of the outbreak and the extent and overall economic effects of the governmental response to the pandemic.

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

Risks Related to Our Business

We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.

We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from environmental groups, landowners, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, have a material adverse effect on our business, financial condition and results of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

For example, in an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the U.S. Army Corps of Engineers (“Corps”) 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing dredge-and-fill activities for pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the Endangered Species Act. The court’s decision vacated NWP 12 until the Corps completes consultation with the applicable federal wildlife agencies. On July 6, 2020, the U.S. Supreme Court granted in part and denied in part the Corps’ request to stay the U.S. District Court’s decision. The Supreme Court’s decision allows the use of NWP 12 as to construction of new oil and gas pipelines, pending the outcome of the appeal to the U.S. Court of Appeals for the Ninth Circuit and any subsequent petition for review to the U.S. Supreme Court. Limitations on the use of NWP 12 may make it more difficult to permit our projects and could cause us to lose potential and current customers and limit our growth and revenue. In addition, on July 6, 2020, the U.S. District Court for the District of Columbia issued an order vacating a Corps Mineral Leasing Act easement for the Dakota Access Pipeline in a lawsuit filed by American Indian Tribes. The court’s decision requires the pipeline to shut down operations by August 5, 2020, until the Corps completes an Environmental Impact Statement in accordance with the National Environmental Policy Act. On July 14, 2020, the U.S. Court of Appeals for the District of Columbia Circuit issued an order temporarily staying the decision pending the court’s review of an emergency motion for a stay filed by the Corps. If the Dakota Access Pipeline is forced to shut down, this could have a material adverse effect on our business, financial condition and results of operations associated with the Polar and Divide System, which interconnects with the Dakota Access Pipeline.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.

We have engaged in transactions in 2020 that generated substantial cancellation of debt (“COD”) income on a per unit basis relative to the trading price of our common units. We may engage in other transactions that result in substantial COD income or other gains in the future, and such events may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder.

A unitholder’s share of our taxable income will include any COD income recognized upon the satisfaction of our outstanding indebtedness for total consideration less than the adjusted issue price (and any accrued but unpaid interest) of such indebtedness. In the first and second quarters of 2020, we commenced a debt buyback program on our Senior Notes, which is ongoing and has resulted in COD income in excess of $54 million. We may engage in other transactions that result in substantial COD income or other gains in the future. Depending upon the net amount of other items related to our loss (or income) allocable to a unitholder, any COD income may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. Furthermore, such COD income event may not be fully offset, either now or in the future, by capital losses, which are subject to significant limitations, or other losses. Accordingly, a COD income event could cause a unitholder to realize taxable income without corresponding future economic benefits or offsetting tax deductions.

Risks Related to an Investment in Us

All of our equity interests in our General Partner and certain of our common units owned by our subsidiary SMP Holdings are pledged as collateral under the SMPH Term Loan; upon the occurrence and during the continuation of an event of default thereunder, the lenders party thereto may gain control of our General Partner and a significant portion of our common units.

On March 21, 2017, SMP Holdings entered into the SMPH Term Loan. The amount of indebtedness outstanding under the SMPH Term Loan was $156 million as of June 15, 2020. The SMPH Term Loan is non-recourse to the

Partnership and its operating subsidiaries. Before it was a subsidiary of the Partnership, SMP Holdings pledged all of the equity interests in our General Partner and 34,604,581 common units as collateral under the SMPH Term Loan. As a result of the GP Buy-In Transaction, such common units are not currently considered outstanding but would be considered outstanding upon the transfer to a third party. If an event of default occurs under the SMPH Term Loan and is continuing, including as a result of SMP Holdings’ failure to comply with its payment or other covenant obligations thereunder or the occurrence of certain bankruptcy or insolvency related events, then the lenders party thereto could foreclose on the collateral securing the SMPH Term Loan. Upon any such foreclosure, such lenders would own the General Partner and, through its ownership of the 34,604,581 common units (which assuming no further issuance of common units, including upon exercise of the ECP Warrants, would represent 44.3% of the outstanding common units upon such foreclosure), have significant influence on matters subject to the vote of our unitholders, including the public election of directors to the Board of Directors commencing in 2022.

Our Partnership Agreement limits the liabilities of our General Partner and the rights of our unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that limit the liability of our General Partner and the rights of our unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:

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whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

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our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; and

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our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

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

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

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

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

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

Our Series A Preferred Units contain covenants that may limit our business flexibility.

Our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66 2/3% of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or the Board of Directors may consider to be in the best interests of our unitholders. The affirmative vote of 66 2/3% of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend the Partnership Agreement in any manner that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series A Preferred Units. The affirmative vote of 66 2/3% of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) under certain circumstances, create or issue certain equity securities that are senior to our common units, (B) declare or pay any distribution to common unitholders out of capital surplus or (C) take any action that would result in an event of default for failure to comply with any covenant in the indentures governing the 5.5% Senior Notes or the 5.75% Senior Notes co-issued by Summit Holdings and its 100% owned finance subsidiary, Finance Corp.

Although holders of the Series A Preferred Units are entitled to limited voting rights with respect to certain matters, the Series A Preferred Units generally vote as a class, separate from our common unitholders, along with any other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable.

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

We received a formal notice from the NYSE on April 10, 2020 indicating noncompliance with the continued listing standard set forth in Rule 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had fallen below $1.00 per unit over a period of 30 consecutive trading days, which is the minimum average unit price for continued listing on the NYSE. We have until December 19, 2020 to regain compliance with the minimum unit price requirement, with the possibility of extension at the discretion of the NYSE. In order to regain compliance, on the last trading day in any calendar month during the cure period, the common units must have: (i) a closing price of at least $1.00 per unit and (ii) an average closing price of at least $1.00 per unit over the 30 trading day period ending on the last trading day of such month. If we fail to regain compliance with Section 802.01C of the NYSE Listed Company Manual by the end of the cure period, the common units will be subject to the NYSE’s suspension and delisting procedures. If the common units ultimately were to be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price of the common units, reduce the number of investors willing to hold or acquire the common units and negatively impact our ability to access equity markets and obtain financing.

Item 5. Other Information.

On August 7, 2020, we entered into an Amendment to Warrants to Purchase Common Units with ECP, ECP NewCo and ECP Holdings (the “Warrant Amendment”) to amend certain terms of the ECP Warrants. Pursuant to the Warrant Amendment, in the event ECP NewCo or ECP Holdings elect to exercise the ECP Warrants for cash prior to February 28, 2021, ECP NewCo and ECP Holdings, at the election and request of the Partnership in its sole discretion, will lend the cash received from such exercise to Summit Holdings (each such loan, a “New ECP Term Loan”). The terms of each New ECP Term Loan will be set forth in the definitive documentation with respect to the New ECP Term Loans and will be based on the terms set forth in the Warrant Amendment.A copy of the Warrant Amendment is included as Exhibit 10.11 to this Current Report on Form 10-Q.

Item 6. Exhibits.

Exhibit number		Description
2.1		Purchase Agreement, dated May 3, 2020, by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-C (SMLP IP), LP, Energy Capital Partners II-C (Summit IP), LP, Energy Capital Partners II (Summit Co-Invest), LP and Summit Midstream Management, LLC, as contributors, SMP TopCo, LLC and SMLP Holdings, LLC, as sellers, Summit Midstream Partners, LP, as the acquiror, and, solely for certain purposes set forth therein, Summit Midstream Partners GP, LLC (Incorporated herein by reference to Exhibit 2.1 to SMLP's Current Report on Form 8-K dated May 5, 2020 (Commission File No. 001-35666))
3.1		~~Third~~Fourth Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated ~~as of March 22, 2019~~May 28, 2020 (Incorporated herein by reference to Exhibit 3.1 to ~~SMLP's~~SMLP’s Current Report on Form 8-K dated ~~March 22, 2019~~June 2, 2020 (Commission File No. 001-35666))
3.2		Second Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated ~~as of October 3, 2012~~May 28, 2020 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed ~~October 4, 2012~~June 2, 2020 (Commission File No. 001-35666))
3.3		Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4		Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1	†	~~Form of Retention Bonus~~Term Loan Credit Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, as borrower, SMP TopCo, LLC, as lender and administrative agent and Mizuho Bank (USA), as collateral agent (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated June ~~11, 2019~~2, 2020 (Commission File ~~Number~~No. 001-35666))
10.2	*	~~Second Amendment~~Term Loan Credit Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, as borrower, SMLP Holdings, LLC, as lender, SMP TopCo, LLC, as administrative agent and Mizuho Bank (USA), as collateral agent (Incorporated herein by reference to ~~Third Amended~~Exhibit 10.2 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.3		Guarantee and ~~Restated~~Collateral Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, Summit Midstream Partners, LP, the subsidiaries listed therein and Mizuho Bank (USA), as collateral agent, relating to the ECP NewCo Term Loan Credit Agreement (Incorporated herein by reference to Exhibit 10.3 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.4		Guarantee and Collateral Agreement, dated May 28, 2020, by and among Summit Midstream Holdings, LLC, Summit Midstream Partners, LP, the subsidiaries listed therein and Mizuho Bank (USA), as collateral agent, relating to the ECP Holdings Term Loan Credit Agreement (Incorporated herein by reference to Exhibit 10.4 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.5		Pari Passu Intercreditor Agreement, dated as of May 28, 2020, among Wells Fargo Bank, National Association, as Revolving Credit Facility Collateral Agent, Mizuho Bank (USA), as NewCo Term Loan Collateral Agent and SMLP Holdings Term Loan Collateral Agent, Summit Midstream Holdings, LLC and other grantors from time to time party thereto (Incorporated herein by reference to Exhibit 10.5 to SMLP’s Current Report on Form 8-K dated June ~~26, 2019~~2, 2020 (Commission File No. 001-35666))
10.6		Warrant to Purchase Common Units, dated May 28, 2020, from Summit Midstream Partners, LP to SMP TopCo, LLC (Incorporated herein by reference to Exhibit 10.6 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.7		Warrant to Purchase Common Units, dated May 28, 2020, from Summit Midstream Partners, LP to SMLP Holdings, LLC (Incorporated herein by reference to Exhibit 10.7 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.8		Operation and Management Services Agreement, dated May 28, 2020, by and among Summit Midstream Partners, LP and Summit Operating Services Company, LLC (Incorporated herein by reference to Exhibit 10.8 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.9		Term Loan Agreement, dated as of March 21, 2017, among Summit Midstream Partners Holdings, LLC, as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent (Incorporated herein by reference to Exhibit 10.9 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))

10.10		Guarantee and Collateral Agreement, dated as of March 21, 2017, by and among Summit Midstream Partners Holdings, LLC, as grantor, Summit Midstream Partners, LLC, as pledgor and grantor and Credit Suisse AG, Cayman Islands Branch, as collateral agent (Incorporated herein by reference to Exhibit 10.10 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
10.11	*	Amendment to Warrants to Purchase Common Units, dated August 7, 2020, by and among Summit Midstream Partners, LP, SMP TopCo, LLC and SMLP Holdings, LLC
22.1		Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities (Incorporated herein by reference to Exhibit 22.1 to SMLP's Report on Form 10-Q filed May 8, 2020 (Commission File No. 001-35666)
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by ~~Leonard W. Mallett,~~Heath Deneke, President, Chief Executive Officer and Director
31.2		Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, Executive Vice President and Chief Financial Officer
32.1		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by ~~Leonard W. Mallett,~~Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer
101.INS	**	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	**	Inline XBRL Taxonomy Extension Schema
101.CAL	**	Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	Inline XBRL Taxonomy Extension Label Linkbase
101.PRE	**	Inline XBRL Taxonomy Extension Presentation Linkbase
104	**	Cover Page Interactive Data File ~~– the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the~~(formatted as Inline XBRL ~~document.~~and contained in Exhibit 101).

~~† Management contract or compensatory plan or arrangement that is incorporated by reference pursuant to Item 9.01(d) of SMLP’s Form 8-K filed June 11, 2019 (Commission File Nos. 001-35666).~~

* Filed herewith.

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

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 ~~9, 2019~~7, 2020	/s/ Marc D. Stratton

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

5770

	Partners' capital
	Limited partners
	Series A Preferred Units			Common			General Partner			Total
	(In thousands)
Partners' capital, January 1, 2019	$	293,616		$	902,358		$	25,250		$	1,221,224
Net income (loss)		7,125			(44,051	)		12			(36,914	)
Conversion of General Partner economic interests		—			22,222			(22,222	)		—
Distributions to unitholders		—			(42,241	)		(3,040	)		(45,281	)
Unit-based compensation		—			2,526			—			2,526
Tax withholdings on vested SMLP LTIP awards		—			(2,522	)		—			(2,522	)
Partners' capital, March 31, 2019		300,741			838,292			—			1,139,033
Net income (loss)		7,125			(2,316	)		—			4,809
Distributions to unitholders		(14,250	)		(23,775	)		—			(38,025	)
Unit-based compensation		—			1,393			—			1,393
Tax withholdings on vested SMLP LTIP awards		—			(95	)		—			(95	)
Partners' capital, June 30, 2019	$	293,616		$	813,499		$	—		$	1,107,115

	Reportable Segments
	Three months ended June 30, 2018
	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	10,422	$	23,106	$	2,509	$	33,661	$	14,080	$	8,050	$	91,828	$	(2,243	)	$	89,585
Natural gas, NGLs and condensate sales		—		7,350		79		4,596		381		—		12,406		19,485			31,891
Other revenues		—		2,960		969		1,178		1,694		—		6,801		(94	)		6,707
Total	$	10,422	$	33,416	$	3,557	$	39,435	$	16,155	$	8,050	$	111,035	$	17,148		$	128,183

	Reportable Segments
	Six months ended June 30, 2018
	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	20,463	$	40,772	$	4,688	$	66,776	$	27,717	$	15,875	$	176,291	$	(2,345	)	$	173,946
Natural gas, NGLs and condensate sales		—		15,196		159		8,841		926		—		25,122		32,886			58,008
Other revenues		—		5,872		1,726		2,389		3,682		—		13,669		(120	)		13,549
Total	$	20,463	$	61,840	$	6,573	$	78,006	$	32,325	$	15,875	$	215,082	$	30,421		$	245,503

	Six months ended May 31, 2019					Six months ended May 31, 2018
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	68,728	$	4,339		$	69,083	$	4,559
Total operating expenses		51,823		5,664			62,293		4,099
Net income (loss)		16,898		(1,326	)		6,784		121

	Three months ended		Six months ended
	June 30, 2019		June 30, 2019
	(In thousands)
Lease cost
Finance lease cost:
Amortization of ROU assets (included in depreciation and amortization)	$	407	$	775
Interest on lease liabilities (included in interest expense)		30		53
Operating lease cost (included in general and administrative expense)		745		1,577
	$	1,182	$	2,405