	September 30,		December 31,
	2020		2019			June 30, 2021		December 31, 2020
	(In thousands, except unit amounts)					(In thousands, except unit amounts)
ASSETS					ASSETS
Cash and cash equivalents	$	50,272	$	9,530	Cash and cash equivalents	$	7,211	$	15,544
Restricted cash		24		27,392	Restricted cash	314		0
Accounts receivable, net		76,497		97,418	Accounts receivable, net	61,233		61,932
Other current assets		4,559		5,521	Other current assets	11,090		4,623
Total current assets		131,352		139,861	Total current assets	79,848		82,099
Property, plant and equipment, net		1,840,284		1,882,489	Property, plant and equipment, net	1,768,897		1,817,546
Intangible assets, net		207,766		232,278	Intangible assets, net	186,525		199,566
Investment in equity method investees		389,088		309,728	Investment in equity method investees	433,440		392,740
Other noncurrent assets		4,989		9,742	Other noncurrent assets	5,335		7,866
TOTAL ASSETS	$	2,573,479	$	2,574,098	TOTAL ASSETS	$	2,474,045	$	2,499,817

LIABILITIES AND CAPITAL					LIABILITIES AND CAPITAL
Trade accounts payable	$	16,205	$	24,415	Trade accounts payable	$	14,824	$	11,878
Accrued expenses		11,353		11,339	Accrued expenses	10,092		13,036
Deferred revenue		17,827		13,493	Deferred revenue	10,593		9,988
Ad valorem taxes payable		6,931		8,477	Ad valorem taxes payable	5,395		9,086
Accrued compensation and employee benefits					Accrued compensation and employee benefits	5,847		9,658
Accrued interest		12,092		12,346	Accrued interest	8,007		8,007
Accrued environmental remediation		1,553		1,725	Accrued environmental remediation	1,959		1,392
Current portion of long-term debt					Current portion of long-term debt	762,000		0
Other current liabilities		10,747		12,206	Other current liabilities	28,209		5,363
Term loan (See TL Restructuring discussion in Note 8)		155,200		5,546
Total current liabilities		231,908		89,547	Total current liabilities	846,926		68,408
Long-term debt		1,390,842		1,622,279
Long-term debt, excluding current portion					Long-term debt, excluding current portion	539,099		1,347,326
Noncurrent deferred revenue		41,755		38,709	Noncurrent deferred revenue	44,857		48,250
Noncurrent accrued environmental remediation		2,003		2,926	Noncurrent accrued environmental remediation	1,192		1,537
Other noncurrent liabilities		4,536		7,951	Other noncurrent liabilities	38,994		21,747
Total liabilities		1,671,044		1,761,412	Total liabilities	1,471,068		1,487,268
Commitments and contingencies (Note 14)
Commitments and contingencies (Note 13)					Commitments and contingencies (Note 13)	0		0

Mezzanine Capital					Mezzanine Capital
Subsidiary Series A Preferred Units (83,842 and 30,058 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)		85,800		27,450
Subsidiary Series A Preferred Units (88,321 and 85,308 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)					Subsidiary Series A Preferred Units (88,321 and 85,308 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)	97,679		89,658

Partners' Capital					Partners' Capital
Series A Preferred Units (237,184 and 300,000 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)		249,351		293,616
Common limited partner capital (56,624,887 and 45,318,866 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)		567,284		305,550
Noncontrolling interest		-		186,070
Series A Preferred Units (143,447 and 162,109 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)					Series A Preferred Units (143,447 and 162,109 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)	161,907		174,425
Common limited partner capital (6,744,926 and 6,110,092 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)					Common limited partner capital (6,744,926 and 6,110,092 units issued and outstanding at June 30, 2021 and December 31, 2020, respectively)	743,391		748,466
Total partners' capital		816,635		785,236	Total partners' capital	905,298		922,891
TOTAL LIABILITIES AND CAPITAL	$	2,573,479	$	2,574,098	TOTAL LIABILITIES AND CAPITAL	$	2,474,045	$	2,499,817


	Three months ended September 30,						Nine months ended September 30,							Three Months Ended June 30,				Six Months Ended June 30,
	2020			2019			2020			2019				2021		2020		2021		2020
	(In thousands, except per-unit amounts)													(In thousands, except per-unit amounts)
Revenues:													Revenues:
Gathering services and related fees	$	71,964		$	80,968		$	229,667		$	243,039		Gathering services and related fees	$	74,233	$	73,911	$	144,580	$	157,703
Natural gas, NGLs and condensate sales		10,783			12,219			35,246			68,438		Natural gas, NGLs and condensate sales	16,416		10,683		37,180		24,463
Other revenues		7,406			7,000			22,150			19,804		Other revenues	9,392		7,413		17,599		14,744
Total revenues		90,153			100,187			287,063			331,281		Total revenues	100,041		92,007		199,359		196,910
Costs and expenses:													Costs and expenses:
Cost of natural gas and NGLs		8,632			7,472			22,945			50,802		Cost of natural gas and NGLs	16,626		6,088		37,102		14,313
Operation and maintenance		22,168			26,231			65,131			74,771		Operation and maintenance	17,507		21,152		34,100		42,963
General and administrative		10,561			10,029			39,908			38,979		General and administrative	29,360		12,786		39,938		29,347
Depreciation and amortization		29,505			27,443			88,801			82,044		Depreciation and amortization	28,364		29,630		56,875		59,296
Transaction costs		726			129			1,944			2,562		Transaction costs	450		1,207		217		1,218
Gain on asset sales, net		(104	)		(347	)		(270	)		(1,595	)	Gain on asset sales, net	(4)		(281)		(140)		(166)
Long-lived asset impairment		—			—			4,475			45,021
Goodwill impairment		—			16,211			—			16,211
Long-lived asset impairments													Long-lived asset impairments	33		654		1,525		4,475
Total costs and expenses		71,488			87,168			222,934			308,795		Total costs and expenses	92,336		71,236		169,617		151,446
Other income		795			12			644			304
Other income (expense), net													Other income (expense), net	(2,334)		276		(2,284)		(151)
Loss on ECP Warrants													Loss on ECP Warrants	(12,159)		0		(13,634)		0
Interest expense		(19,018	)		(23,462	)		(64,836	)		(68,547	)	Interest expense	(15,502)		(21,990)		(29,455)		(45,818)
Gain on early extinguishment of debt		24,690			—			78,925			—		Gain on early extinguishment of debt	0		54,235		0		54,235
Income (loss) before income taxes and equity method investment income (loss)		25,132			(10,431	)		78,862			(45,757	)
Income tax benefit (expense)		(298	)		(21	)		104			(1,427	)
Income (loss) from equity method investees		795			(677	)		7,146			(1,197	)
Income (loss) before income taxes and equity method investment income													Income (loss) before income taxes and equity method investment income	(22,290)		53,292		(15,631)		53,730
Income tax benefit													Income tax benefit	248		389		262		402
Income from equity method investees													Income from equity method investees	2,304		3,040		4,619		6,351
Net income (loss)	$	25,629		$	(11,129	)	$	86,112		$	(48,381	)	Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483
Less:
Net income (loss) attributable to noncontrolling interest		—			(10,340	)		(3,274	)		(37,251	)
Net income (loss) attributable to limited partners		25,629			(789	)		89,386			(11,130	)
Net income attributable to Series A Preferred Units		6,481			7,125			20,731			21,375
Net income attributable to Subsidiary Series A Preferred Units		7,298			—			9,640			—		Net income attributable to Subsidiary Series A Preferred Units	(4,089)		(1,397)		(8,021)		(2,342)
Add:
Deemed contribution on exchange of preferred units		54,945			—			54,945			—
Net loss attributable to noncontrolling interest													Net loss attributable to noncontrolling interest	0		1,393		0		3,274
Net income (loss) attributable to Summit Midstream Partners, LP													Net income (loss) attributable to Summit Midstream Partners, LP	$	(23,827)	$	56,717	$	(18,771)	$	61,415
Less: net income attributable to Series A Preferred Units													Less: net income attributable to Series A Preferred Units	(3,849)		(7,125)		(8,136)		(14,250)
Add: deemed contribution from 2021 Preferred Exchange Offer													Add: deemed contribution from 2021 Preferred Exchange Offer	8,326		0		8,326		0
Net income (loss) attributable to common limited partners	$	66,795		$	(7,914	)	$	113,960		$	(32,505	)	Net income (loss) attributable to common limited partners	$	(19,350)	$	49,592	$	(18,581)	$	47,165

Net income (loss) per limited partner unit:													Net income (loss) per limited partner unit:
Common unit – basic	$	1.29		$	(0.17	)	$	2.41		$	(0.72	)	Common unit – basic	$	(2.91)	$	16.66	$	(2.91)	$	15.73
Common unit – diluted	$	1.25		$	(0.17	)	$	2.34		$	(0.72	)	Common unit – diluted	$	(2.91)	$	15.92	$	(2.91)	$	15.27

Weighted-average limited partner units outstanding:													Weighted-average limited partner units outstanding:
Common units – basic		51,974			45,319			47,331			45,319		Common units – basic	6,656		2,977		6,392		2,999
Common units – diluted		53,650			45,319			48,782			45,319		Common units – diluted	6,656		3,116		6,392		3,088

Noncontrolling Interest

Partners' Capital

Series A Preferred Units

Common Noncontrolling Interests ⁽¹⁾

Series A Preferred Units

Partners' Capital

Total

(In thousands)

Partners' capital, January 1, 2020

$
293,616

$
186,070

$
—

$
305,550

$
785,236

Net income (loss)

7,125

(1,881
)

—

(2,427
)

2,817

Net cash distributions to SMLP
    unitholders

—

(6,037
)

—

—

(6,037
)
Unit-based compensation

—

2,723

—

—

2,723

Effect of common unit issuances under
    SMLP LTIP

—

2,322

—

(2,322
)

—

Tax withholdings and associated
    payments on vested SMLP LTIP
    awards

—

(984
)

—

—

(984
)
Partners' capital, March 31, 2020

300,741

182,213

—

300,801

783,755

Net income (loss)

4,750

(1,393
)

2,375

49,592

55,324

Unit-based compensation

—

1,331

—

515

1,846

Tax withholdings and associated
    payments on vested SMLP LTIP
    awards

—

(34
)

—

(28
)

(62
)
GP Buy-In Transaction assumption of
    noncontrolling interest in SMLP

(305,491
)

(182,117
)

305,491

182,117

—

Repurchase of common units under GP
    Buy-In Transaction

—

—

—

(44,078
)

(44,078
)
Other

—

—

—

(61
)

(61
)
Partners' capital, June 30, 2020

—

—

307,866

488,858

796,724

Net income (loss)

—

—

6,481

11,850

18,331

Unit-based compensation

—

—

—

1,622

1,622

Tax withholdings and associated
   payments on vested SMLP LTIP
    awards

—

—

—

(117
)

(117
)
Tax withholdings on Series A Preferred
    Unit Exchange

—

—

—

(237
)

(237
)
Conversion of Series A Preferred Units to
    SMLP common units inclusive of a
    $54.9 million deemed contribution to
    common unit holders (Note 10)

—

—

(64,996
)

64,996

—

Other

—

—

—

312

312

Partners' capital, September 30, 2020

$
-

$
-

$
249,351

$
567,284

$
816,635


	Noncontrolling Interest				Partners' Capital
	Series A Preferred Units		Common Noncontrolling Interests		Series A Preferred Units		Partners' Capital		Total
	(In thousands)
Partners' capital, January 1, 2021	$	0	$	0	$	174,425	$	748,466	$	922,891
Net income	—		—		4,287		769		5,056
Unit-based compensation	—		—		—		1,967		1,967
Tax withholdings and associated payments on vested SMLP LTIP awards	—		—		—		(1,274)		(1,274)
Partners' capital, March 31, 2021	0		0		178,712		749,928		928,640
Net income (loss)	—		—		3,849		(27,676)		(23,827)
Unit-based compensation	—		—		—		1,048		1,048
Tax withholdings and associated payments on vested SMLP LTIP awards	—		—		—		(98)		(98)
Tax withholdings on 2021 Preferred Exchange Offer	—		—		—		(465)		(465)
Effect of 2021 Preferred Exchange Offer, inclusive of an $8.3 million deemed contribution to common unit holders (Note 9)	—		—		(20,654)		20,654		0
Partners' capital, June 30, 2021	$	0	$	0	$	161,907	$	743,391	$	905,298

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

Noncontrolling Interest

Series A Preferred Units

Common Noncontrolling Interests⁽¹⁾

Partners' Capital

Total

(In thousands)

Partners' capital, January 1, 2019

$
293,616

$
554,472

$
543,479

$
1,391,567

Net income (loss)

7,125

(25,570
)

(21,835
)

(40,280
)
Net cash distributions to SMLP unitholders

—

(27,374
)

—

(27,374
)
Unit-based compensation

—

2,526

—

2,526

Effect of common unit issuances under
    SMLP LTIP

—

2,387

(2,387
)

—

Tax withholdings and associated
    payments on vested SMLP LTIP
    awards

—

(2,524
)

—

(2,524
)
Conversion of noncontrolling interest related
    to cancellation of subsidiary incentive
    distribution rights

—

(48,203
)

48,203

—

Partners' capital, March 31, 2019

300,741

455,714

567,460

1,323,915

Net income (loss)

7,125

(1,341
)

(2,756
)

3,028

Net cash distributions to SMLP unitholders

(14,250
)

(13,826
)

—

(28,076
)
Net cash distributions to Energy Capital
    Partners

—

—

(68,984
)

(68,984
)
Unit-based compensation

—

1,393

—

1,393

Effect of common unit issuances under
    SMLP LTIP

—

40

(40
)

—

Tax withholdings and associated
    payments on vested SMLP LTIP
    awards

—

(93
)

—

(93
)
Partners' capital, June 30, 2019

293,616

441,887

495,680

1,231,183

Net income (loss)

7,125

(10,340
)

(7,914
)

(11,129
)
Net cash distributions to SMLP unitholders

—

(13,829
)

—

(13,829
)
Unit-based compensation

—

1,451

—

1,451

Effect of common unit issuances under
    SMLP LTIP

—

173

(173
)

—

Tax withholdings and associated
    payments on vested SMLP LTIP
    awards

—

55

—

55

Partners' capital, September 30, 2019

$
300,741

$
419,397

$
487,593

$
1,207,731


	Six Months Ended June 30,
	2021		2020
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(10,750)	$	60,483
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	57,344		59,766
Noncash lease expense	519		1,557
Amortization of debt issuance costs	3,447		3,136
Unit-based and noncash compensation	3,015		4,569
Income from equity method investees	(4,619)		(6,351)
Distributions from equity method investees	13,116		12,749
Gain on asset sales, net	(140)		(166)
Loss on ECP Warrants	13,634		0
Unsettled loss on interest rate swaps	2,692		0
Gain on extinguishment of debt	0		(54,235)
Long-lived asset impairment	1,525		4,475
Changes in operating assets and liabilities:
Accounts receivable	(1,993)		20,219
Trade accounts payable	2,989		1,411
Accrued expenses	(3,127)		(8)
Deferred revenue, net	(2,787)		5,500
Ad valorem taxes payable	(3,691)		(2,170)
Accrued interest	0		(609)
Accrued environmental remediation, net	(512)		(545)
Other, net	15,555		(4,410)
Net cash provided by operating activities	86,217		105,371
Cash flows from investing activities:
Capital expenditures	(5,962)		(27,426)
Proceeds from asset sale	8,000		0
Investment in Double E equity method investee	(48,943)		(79,728)
Other, net	0		217
Net cash used in investing activities	(46,905)		(106,937)
Cash flows from financing activities:
Net cash distributions to noncontrolling interest SMLP unitholders	0		(6,037)
Borrowings under Revolving Credit Facility	—		90,000
Repayments on Revolving Credit Facility	(95,000)		(34,000)
Borrowings under Permian Transmission Credit Facility	53,500		—
Repayments on SMPH Term Loan	0		(6,300)

Repurchase of Senior Notes	0		(76,707)
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs	0		48,710
Borrowings under ECP Loans	0		35,000
Purchase of common units in GP Buy-In Transaction	0		(41,778)
Debt issuance costs	(5,179)		(1,080)
Proceeds from asset sale	260		288
Other, net	(912)		(1,833)
Net cash provided by (used in) financing activities	(47,331)		6,263
Net change in cash, cash equivalents and restricted cash	(8,019)		4,697
Cash, cash equivalents and restricted cash, beginning of period	15,544		36,922
Cash, cash equivalents and restricted cash, end of period	$	7,525	$	41,619

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

Nine months ended September 30,

2020

2019

(In thousands)

Cash flows from operating activities:

Net income (loss)

$
86,112

$
(48,381
)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:

Depreciation and amortization

89,505

83,030

Noncash lease expense

1,925

2,299

Amortization of debt issuance costs

4,870

4,719

Unit-based and noncash compensation

6,191

5,370

(Income) loss from equity method investees

(7,146
)

1,197

Distributions from equity method investees

19,859

28,008

Gain on asset sales, net

(270
)

(1,595
)
Gain on early extinguishment of debt

(78,925
)

0

Gain on fair value of warrants

(838
)

0

Long-lived asset impairment

4,475

45,021

Goodwill impairment

0

16,211

Changes in operating assets and liabilities:

Accounts receivable

20,922

8,363

Trade accounts payable

470

820

Accrued expenses

(1,078
)

(11,965
)
Deferred revenue, net

7,379

1,910

Ad valorem taxes payable

(1,546
)

(2,061
)
Accrued interest

2,680

3,065

Accrued environmental remediation, net

(1,368
)

(2,025
)
Other, net

(6,410
)

(6,369
)
Net cash provided by operating activities

146,807

127,617

Cash flows from investing activities:

Capital expenditures

(35,312
)

(151,663
)
Proceeds from asset sale (net of cash of $1,475 for the
period ended September 30, 2019)

0

90,111

Distribution from equity method investment

0

7,252

Investment in equity method investee

(92,072
)

(11,330
)
Other, net

2,486

343

Net cash used in investing activities

(124,898
)

(65,287
)
Cash flows from financing activities:

Net cash distributions to noncontrolling interest SMLP unitholders

(6,037
)

(55,029
)
Series A Preferred Unit distributions

0

(14,250
)
Net cash distributions to Energy Capital Partners

0

(68,984
)
Borrowings under Revolving Credit Facility

165,500

265,000

Repayments on Revolving Credit Facility

(34,000
)

(131,000
)
Repayments on SMPH Term Loan

(6,300
)

(59,500
)
Open Market Repurchases of 2022 and 2025 Senior Notes (Note 8)

(82,844
)

0

Tender Offers of 2022 and 2025 Senior Notes (Note 8)

(48,712
)

0

Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs

48,710

0

Borrowings under ECP Loans (Note 8)

35,000

0

Repayment of ECP Loans (Note 8)

(35,000
)

0

Purchase of common units in GP Buy-In Transaction

(41,778
)

0

Debt issuance costs

(835
)

(584
)
Proceeds from asset sale

288

0

Other, net

(2,527
)

(3,930
)
Net cash provided by (used in) financing activities

(8,535
)

(68,277
)
Net change in cash, cash equivalents and restricted cash

13,374

(5,947
)
Cash, cash equivalents and restricted cash, beginning of period

36,922

16,173

Cash, cash equivalents and restricted cash, end of period

$
50,296

$
10,226

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

Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. For more detailed information about reportable segments, see Note 1615 – Segment Information.

Three months ended September 30, 2020

Gathering services and related fees

Natural gas, NGLs and condensate sales

Other revenues

Total

(in thousands)

Reportable Segments:

Utica Shale

$
8,385

$
0

$
0

$
8,385

Williston Basin

10,941

4,958

3,136

19,035

DJ Basin

6,051

17

826

6,894

Permian Basin

2,595

4,803

168

7,566

Piceance Basin

26,576

528

1,233

28,337

Barnett Shale

10,545

477

1,399

12,421

Marcellus Shale

6,871

0

0

6,871

Total reportable segments

71,964

10,783

6,762

89,509

All other segments

0

0

644

644

Total

$
71,964

$
10,783

$
7,406

$
90,153

Three months ended September 30, 2019

Gathering services and related fees

Natural gas, NGLs and condensate sales

Other revenues

Total

(in thousands)

Reportable Segments:

Utica Shale

$
8,865

$
0

$
0

$
8,865

Williston Basin

16,685

1,878

2,555

21,118

DJ Basin

7,039

93

735

7,867

Permian Basin

986

3,797

102

4,885

Piceance Basin

30,120

1,733

1,258

33,111

Barnett Shale

11,286

4,828

1,706

17,820

Marcellus Shale

5,987

0

0

5,987

Total reportable segments

80,968

12,329

6,356

99,653

All other segments

0

(110
)

644

534

Total

$
80,968

$
12,219

$
7,000

$
100,187


	Nine months ended September 30, 2020									Three Months Ended June 30, 2021
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total			Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)									(in thousands)
Reportable Segments:									Reportable Segments:
Utica Shale	$	26,885	$	0	$	0	$	26,885	Utica Shale	$	11,349	$	0	$	0	$	11,349
Williston Basin		47,145		12,413		9,054		68,612	Williston Basin	12,516		8,201		4,242		24,959
DJ Basin		18,134		158		2,853		21,145	DJ Basin	5,891		305		1,856		8,052
Permian Basin		7,617		13,537		481		21,635	Permian Basin	2,262		6,875		121		9,258
Piceance Basin		79,987		1,932		3,394		85,313	Piceance Basin	25,527		1,025		1,233		27,785
Barnett Shale		30,865		7,206		4,437		42,508	Barnett Shale	10,076		10		1,012		11,098
Marcellus Shale		19,034		0		0		19,034	Marcellus Shale	6,612		0		0		6,612
Total reportable segments		229,667		35,246		20,219		285,132	Total reportable segments	74,233		16,416		8,464		99,113
All other segments		0		0		1,931		1,931
Corporate and Other									Corporate and Other	0		0		928		928
Total	$	229,667	$	35,246	$	22,150	$	287,063	Total	$	74,233	$	16,416	$	9,392	$	100,041

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

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

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

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

⁽¹⁾ As a result of the GP Buy-In Transaction, the Partnership recast its historical financial statements, which resulted in a recasted SMLP common limited partner unit count of 45.3 million units at December 31, 2019. Prior to the GP Buy-In Transaction, the SMLP common limited partner unit count was 94.5 million units, and after adjusting for (i) the effect of 1.0 million SMLP units issued

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

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

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

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

~~With respect to our Subsidiary Series A Preferred Units relating to~~ Upon the ~~three and nine months ended September 30, 2020,~~resumption of distributions, the Partnership ~~declared a PIK~~Agreement requires that it distribute all available cash, subject to reserves established by its General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under this policy is subject to fluctuations based on the amount of cash the Partnership generates from its business and the decision to make any distribution is determined by the General Partner, taking into consideration the terms of the ~~quarterly~~Partnership Agreement. The Partnership’s last distribution ~~which resulted in~~was paid on February 14, 2020, to unitholders of record at the ~~issuance~~close of 45 Subsidiary Series A Preferred Units and 1,442 Subsidiary Series A Preferred Units, respectively. This PIK amount equates to a distribution of $32.1133 and $17.5099 per Subsidiary Series A Preferred Unit for the three and nine months ended September 30, 2020, respectively, or $70business on an annualized basis. In addition, the Partnership issued approximately 38 Subsidiary Series A Preferred Units related to the remaining undrawn commitment (as defined in the underlying agreement with TPG Energy Solutions Anthem, L.P.) as of and for the nine months ended September 30,February 7, 2020.


	Three months ended September 30,					Nine months ended September 30,						Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019			2020		2019				2021		2020		2021		2020
	(In thousands, except per-unit amounts)											(In thousands, except per-unit amounts)				(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:											Numerator for basic and diluted EPU:
Allocation of net income (loss) among limited partner interests:											Allocation of net income (loss) among limited partner interests:
Net income (loss) attributable to limited partners	$	25,629	$	(789	)	$	89,386	$	(11,130	)
Less:
Net income attributable to Series A Preferred Units		6,481		7,125			20,731		21,375
Net income (loss)											Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483
Net income attributable to Subsidiary Series A Preferred Units		7,298		—			9,640		—		Net income attributable to Subsidiary Series A Preferred Units	(4,089)		(1,397)		(8,021)		(2,342)
Add:
Deemed capital contribution from Series A Preferred Unit Exchange Offer		54,945		—			54,945		—
Net loss attributable to noncontrolling interest											Net loss attributable to noncontrolling interest	0		1,393		0		3,274
Net income (loss) attributable to Summit Midstream Partners, LP											Net income (loss) attributable to Summit Midstream Partners, LP	(23,827)		56,717		(18,771)		61,415

Less: Net income attributable to Series A Preferred Units											Less: Net income attributable to Series A Preferred Units	(3,849)		(7,125)		(8,136)		(14,250)
Add: Deemed capital contribution from 2021 Preferred Exchange Offer											Add: Deemed capital contribution from 2021 Preferred Exchange Offer	8,326		0		8,326		0
Net income (loss) attributable to common limited partners	$	66,795	$	(7,914	)	$	113,960	$	(32,505	)	Net income (loss) attributable to common limited partners	(19,350)		$	49,592	(18,581)		$	47,165

Denominator for basic and diluted EPU:											Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic⁽¹⁾		51,974		45,319			47,331		45,319
Weighted-average common units outstanding – basic											Weighted-average common units outstanding – basic	6,656		2,977		6,392		2,999
Effect of nonvested phantom units		1,676		—			1,451		—		Effect of nonvested phantom units	0		139		0		89
Weighted-average common units outstanding – diluted		53,650		45,319			48,782		45,319		Weighted-average common units outstanding – diluted	6,656		3,116		6,392		3,088

Net Income (Loss) per limited partner unit:											Net Income (Loss) per limited partner unit:
Common unit – basic	$	1.29	$	(0.17	)	$	2.41	$	(0.72	)	Common unit – basic	$	(2.91)	$	16.66	$	(2.91)	$	15.73
Common unit – diluted	$	1.25	$	(0.17	)	$	2.34	$	(0.72	)	Common unit – diluted	$	(2.91)	$	15.92	$	(2.91)	$	15.27

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		4,031		176			3,353		70		Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU	169		276		173		201

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

Table of the Reverse Unit Split will be rounded to the nearest whole number of common units. Once effective, the number of outstanding shares of common units will be reduced from 56,624,887 common units as of October 30, 2020 to 3,774,992 common units. Contents

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

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of ~~SMLP~~the Partnership and its subsidiaries for the periods since December 31, ~~2019.~~2020. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the ~~2019~~Partnership’s Annual ~~Report.~~Report on Form 10-K for the year ended December 31, 2020 (the “2020 Annual Report”). Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.

~~This MD&A comprises the following sections:~~

•

~~Overview~~

•

~~Trends and Outlook~~

•

~~How We Evaluate Our Operations~~

Overview

•

~~Results of Operations~~

•

~~Liquidity and Capital Resources~~

•

~~Critical Accounting Estimates~~

•

~~Forward-Looking Statements~~

~~Overview~~

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

We classify our midstream energy infrastructure assets into two ~~categories:~~

•

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

categories, our Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and Legacy Areas are summarized below.

•

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

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

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to

fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers onin the ~~Bison Midstream, Grand River~~Williston Basin, Piceance Basin, and ~~Summit~~ Permian ~~systems,~~Basin segments, (ii) the sale of natural gas we retain from certain ~~DFW Midstream~~Barnett Shale customers and (iii) the sale of condensate we retain from our gathering services ~~at Grand River.~~in the Piceance Basin segment. During the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, these additional activities accounted for approximately ~~12%~~16% and 19% of total ~~revenues.~~

revenues, respectively.

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

Table of Contents

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the "Segment Overview for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019"~~2020" section included herein.


	Three months ended September 30,						Nine months ended September 30,							Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019				2021			2020			2021			2020
	(In thousands)													(In thousands)
Net income (loss)	$	25,629		$	(11,129	)	$	86,112		$	(48,381	)	Net income (loss)	$	(19,738)		$	56,721		$	(10,750)		$	60,483
Reportable segment adjusted EBITDA													Reportable segment adjusted EBITDA
Utica Shale	$	7,453		$	7,864		$	24,074		$	20,697		Utica Shale	$	10,652		$	10,693		$	18,372		$	16,621
Ohio Gathering		7,129			10,435			22,582			29,584		Ohio Gathering	6,841			7,514			13,713			15,453
Williston Basin		11,713			13,840			40,632			49,224		Williston Basin	9,626			12,727			20,431			28,919
DJ Basin		4,766			6,554			15,016			12,043		DJ Basin	5,106			4,339			10,453			10,250
Permian Basin		893			210			4,302			(996	)	Permian Basin	461			1,828			1,170			3,409
Piceance Basin		21,503			24,044			66,794			74,627		Piceance Basin	20,324			21,734			41,358			45,291
Barnett Shale		7,205			10,901			24,475			33,483		Barnett Shale	8,889			8,510			16,905			17,270
Marcellus Shale		6,022			4,958			16,230			14,735		Marcellus Shale	5,868			4,888			11,469			10,208

Net cash provided by operating activities	$	41,436		$	43,043		$	146,807		$	127,617		Net cash provided by operating activities	$	34,787		$	35,170		$	86,217		$	105,371
Capital expenditures ⁽¹⁾		7,886			40,571			35,312			151,663		Capital expenditures (1)	3,352			8,843			5,962			27,426
Investment in equity method investee		12,344			5,409			92,072			11,330
Investment in Double E equity method investee (2)													Investment in Double E equity method investee (2)	43,324			21,695			48,943			79,728

Net cash distributions to noncontrolling interest SMLP unitholders	$	—		$	13,829		$	6,037		$	55,029
Series A Preferred Unit distributions		—			—			—			14,250
Net borrowings under Revolving Credit Facility		75,500			27,000			131,500			134,000
Repayments on SMPH term loan		—			(5,750	)		(6,300	)		(59,500	)
Open Market Repurchases of 2022 and 2025 Senior Notes (Note 8)		(6,137	)		—			(82,844	)		—
Tender Offers of 2022 and 2025 Senior Notes (Note 8)		(48,712	)		—			(48,712	)		—
Borrowings under Revolving Credit Facility													Borrowings under Revolving Credit Facility	—			35,000			—			90,000
Repayments on Revolving Credit Facility													Repayments on Revolving Credit Facility	(40,000)			—			(95,000)			(34,000)
Repayment of SMP Holdings Term Loan													Repayment of SMP Holdings Term Loan	—			(5,500)			—			(6,300)
Borrowings under Permian Transmission Credit Facility													Borrowings under Permian Transmission Credit Facility	36,000			—			53,500
Repurchase of Senior Notes													Repurchase of Senior Notes	—			(76,707)			—			(76,707)
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs ⁽²⁾		—			—			48,710			—		—			14,764			—			47,810
Purchase of common units in GP Buy-In Transaction		—			—			(41,778	)		—		Purchase of common units in GP Buy-In Transaction	—			(41,778)			—			(41,778)

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

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

~~Key matters for three~~$0.6 million and ~~nine months ended September 30, 2020.The following items are reflected in our financial results:~~

•

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

•

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

•

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

•

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

•

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

~~Key matters~~ for the three ~~and nine~~ months ended ~~September~~June 30, ~~2019.~~2021 and 2020 respectively, and ~~The following items are reflected in our financial results:~~$1.6 million

•

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

•

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

~~In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6~~and $0.3 million for ~~a 70% ownership interest in Double E. We own a majority interest in~~ the ~~Double E Project~~six months ended June 30, 2021 and ~~are leading efforts to develop, permit and construct the pipeline. Upon commissioning, we will operate the pipeline.~~

•2020 respectively.

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

•

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

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

Trends and Outlook

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

•

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

•

~~Production from U.S. shale plays;~~

•

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

•

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

•

Ongoing impact ~~of the COVID-19 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 nine months of 2020, we are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. Given the dynamic nature of the COVID-19 pandemic and ~~related market conditions, we cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have~~its effect 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~~demand and ~~cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses~~prices for oil;

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

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

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the ~~2019~~2020 Annual Report.

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;~~

•throughput volume;

~~revenues;~~

•revenues;

~~operation and maintenance expenses; and~~

•operation and maintenance expenses; and

~~segment adjusted EBITDA.~~

•segment adjusted EBITDA.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three and ~~nine~~six months ended ~~September~~June 30, ~~2020.~~

2021.

Additional Information. For additional information, see the "Results of Operations" section herein and the notes to the unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the "How We Evaluate Our Operations" section of MD&A included in the ~~2019~~2020 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 – Summary of Significant Accounting ~~Policies.~~Policies and Recently Issued Accounting Standards applicable to the Partnership.

Table of Contents

Results of Operations

Consolidated Overview for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~

2020

The following table presents certain consolidated financial and operating data.


	Three months ended September 30,						Nine months ended September 30,							Three Months Ended June 30,				Six Months Ended June 30,
	2020			2019			2020			2019				2021		2020		2021		2020
	(In thousands)													(In thousands)				(In thousands)
Revenues:													Revenues:
Gathering services and related fees	$	71,964		$	80,968		$	229,667		$	243,039		Gathering services and related fees	$	74,233	$	73,911	$	144,580	$	157,703
Natural gas, NGLs and condensate sales		10,783			12,219			35,246			68,438		Natural gas, NGLs and condensate sales	16,416		10,683		37,180		24,463
Other revenues		7,406			7,000			22,150			19,804		Other revenues	9,392		7,413		17,599		14,744
Total revenues		90,153			100,187			287,063			331,281		Total revenues	100,041		92,007		199,359		196,910
Costs and expenses:													Costs and expenses:
Cost of natural gas and NGLs		8,632			7,472			22,945			50,802		Cost of natural gas and NGLs	16,626		6,088		37,102		14,313
Operation and maintenance		22,168			26,231			65,131			74,771		Operation and maintenance	17,507		21,152		34,100		42,963
General and administrative		10,561			10,029			39,908			38,979
General and administrative (2)													General and administrative (2)	29,360		12,786		39,938		29,347
Depreciation and amortization		29,505			27,443			88,801			82,044		Depreciation and amortization	28,364		29,630		56,875		59,296
Transaction costs		726			129			1,944			2,562		Transaction costs	450		1,207		217		1,218
Gain on asset sales, net		(104	)		(347	)		(270	)		(1,595	)	Gain on asset sales, net	(4)		(281)		(140)		(166)
Long-lived asset impairment		—			—			4,475			45,021		Long-lived asset impairment	33		654		1,525		4,475
Goodwill Impairment		—			16,211			—			16,211
Total costs and expenses		71,488			87,168			222,934			308,795		Total costs and expenses	92,336		71,236		169,617		151,446
Other income		795			12			644			304
Other income (expense), net													Other income (expense), net	(2,334)		276		(2,284)		(151)
Loss on ECP Warrants													Loss on ECP Warrants	(12,159)		—		(13,634)		—
Interest expense		(19,018	)		(23,462	)		(64,836	)		(68,547	)	Interest expense	(15,502)		(21,990)		(29,455)		(45,818)
Gain on early extinguishment of debt		24,690			—			78,925			—		Gain on early extinguishment of debt	—		54,235		—		54,235
Income (loss) before income taxes and equity method investment income (loss)		25,132			(10,431	)		78,862			(45,757	)
Income tax benefit (expense)		(298	)		(21	)		104			(1,427	)
Income (loss) from equity method investees		795			(677	)		7,146			(1,197	)
Income (loss) before income taxes and equity method investment income													Income (loss) before income taxes and equity method investment income	(22,290)		53,292		(15,631)		53,730
Income tax benefit													Income tax benefit	248		389		262		402
Income from equity method investees													Income from equity method investees	2,304		3,040		4,619		6,351
Net income (loss)	$	25,629		$	(11,129	)	$	86,112		$	(48,381	)	Net income (loss)	$	(19,738)	$	56,721	$	(10,750)	$	60,483

Volume throughput (1):
Volume throughput (1):													Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,392			1,394			1,354			1,410		Aggregate average daily throughput - natural gas (MMcf/d)	1,441		1,391		1,393		1,336
Aggregate average daily throughput - liquids (Mbbl/d)		69			105			81			101		Aggregate average daily throughput - liquids (Mbbl/d)	63		76		64		87

Natural gas throughput volumes ~~decreased 2~~increased50 MMcf/d for the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~September~~June 30, ~~2019,~~2020, primarily reflecting:

•

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

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

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

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

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

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

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

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

Table of Contents

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

•

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

Natural gas throughput volumes ~~decreased 56~~increased57 MMcf/d for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, primarily reflecting:

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

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

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

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

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

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

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

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

•

~~a volume throughput increase of 8 MMcf/d for the Marcellus Shale~~•a volume throughput decrease of 4 MMcf/d for the Permian Basin segment.

Volumes – Liquids.

Crude oil and produced water throughput volumes at the Williston segment decreased 36 13Mbbl/d and 20 23Mbbl/d, respectively, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020, respectively,~~2021, compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020, primarily as a result of natural production declines as well as a lower number of new well connects.

For additional information on volumes, see the "Segment Overview for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019"~~2020" section herein.

Revenues. Total revenues ~~decreased $10.0~~increased $8.0 million during the three months ended ~~September~~June 30, 2021 compared to the prior year period, comprised of a $5.7 million increasein natural gas, NGLs and condensate sales, a $0.3 million increase in gathering services and related fees and a $2.0 million increase in Other Revenues.

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

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

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

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

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

Total revenues increased $2.4 million during the six months ended June 30, 2021 compared to the prior year period, primarily comprised of a ~~$9.0~~$12.7 million increase in natural gas, NGLs and condensate sales, a $2.9 million increase in Other Revenues, offset by a $13.1 million decrease in gathering services and related fees.

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

•an $11.1 million decrease in gathering services and related fees in the Williston Basin, primarily due to lower liquids volume throughput and the expiration of a ~~$1.4 million decrease in~~customer’s minimum volume commitment. Lower volumes are primarily associated with natural ~~gas, NGLs and condensate sales.~~

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

•

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

•

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

•

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

•

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

•

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

•

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

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

~~Total revenues decreased $44.2 million~~number of new well connects during the ~~nine months ended September 30, 2020 compared to the prior year period primarily comprised of~~ period;

•a ~~$33.2 million decrease in natural gas, NGLs and condensate sales and a $13.4~~$3.1 million decrease in gathering services and related ~~fees.~~

~~Gathering Services~~fees in the Piceance Basin related to lower volume throughput due to a lack of drilling and ~~Related Fees~~completion activity and natural production declines; and~~. Gathering~~

•a partially offsetting $1.4 million increasein gathering services and related fees ~~decreased $13.4 million compared to~~in the ~~nine months ended September 30, 2019,~~Utica Shale, primarily ~~reflecting:~~

as a result of the completion of new wells that were commissioned in March 2021, partially offset by natural production declines on existing wells.

•

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

•

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

•

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

•

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

•

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

•

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

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate ~~sales decreased $33.2~~revenues increased$12.7 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019, primarily reflecting lower natural gas, NGL~~2020, reflecting:

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

•a $4.7 million increase in revenues in the Permian Basin; and ~~crude oil marketing services. The majority of~~

•a $1.5 million increase in revenues in the ~~decrease in revenue is~~Piceance Basin; partially offset by

•a ~~$27.9~~$6.7 million decrease in ~~natural gas, NGL and condensate purchases.~~

revenues in the Barnett Shale.

Costs and Expenses. Total costs and expenses ~~decreased $15.7~~increased $21.1 million during the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~September~~June 30, 2019, primarily due to a $16.2 million decrease from a noncash goodwill impairment charge in 2019 and a $4.1 million decrease in operation and maintenance expense partially offset by a $2.1 million increase in depreciation and amortization expense and a $1.2 million increase in natural gas, NGLs and condensate purchases.2020.

Table of Contents

Total costs and expenses ~~decreased $85.7~~increased $18.2 million during the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to the ~~nine~~six months ended ~~September~~June 30, 2019, primarily due to the impact of: (i) the March 2019 recognition of a $34.9 million and $10.2 million long-lived asset impairment in the DJ Basin and Barnett Shale, respectively, (ii) the September of 2019 recognition of a $16.2 million noncash goodwill impairment charge in the Marcellus Shale, (iii) a $27.9 million decrease in natural gas, NGLs and condensate purchases and (iv) a $9.6 million decrease in operating and maintenance expense, partially offset by (v) the March 2020 recognition of a $3.6 million long-lived asset impairment in the DJ Basin and (vi) a $6.8 million increase in depreciation and amortization expense.

2020.

Cost of Natural Gas and NGLs.Cost of natural gas and NGLs increased ~~$1.2~~$10.5 million for the three months ended ~~September~~June 30, ~~2020 and decreased $27.9 million for the nine months ended September 30, 2020~~2021 compared to the three ~~and nine~~ months ended ~~September~~June 30, ~~2019,~~2020, primarily driven by ~~lower~~an increase in commodity prices.

Cost of natural gas ~~NGL~~ and ~~crude oil marketing activity.~~

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

Operation and Maintenance. Operation and maintenance expense decreased ~~$4.1~~$3.6 million and $8.9 million for the three and six months ended June 30, 2021, respectively, compared to the three and six months ended June 30, 2020, primarily due to reduced employee headcount as a result of restructuring activities implemented in the fourth quarter of 2020. The Partnership realized $5.6 million of benefits during the six months ended June 30, 2021, that are not otherwise expected to occur in 2022 and future periods, as a result of commercial settlements and the ERC Tax Credit.

Segment Overview for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~


	Utica Shale															Utica Shale
	Three months ended September 30,							Nine months ended September 30,								Three Months Ended June 30,					Six Months Ended June 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)															(Dollars in thousands)					(Dollars in thousands)
Revenues:															Revenues:
Gathering services and related fees	$	8,385		$	8,865		(5%)	$	26,885		$	23,951		12%	Gathering services and related fees	$	11,349	$	11,538	(2)%	$	19,920	$	18,500	8%
Total revenues		8,385			8,865		(5%)		26,885			23,951		12%	Total revenues	11,349		11,538		(2)%	19,920		18,500		8%
Costs and expenses:															Costs and expenses:
Operation and maintenance		877			911		(4%)		2,575			2,998		(14%)	Operation and maintenance	658		757		(13%)	1,436		1,698		(15%)
General and administrative		50			85		(41%)		222			242		(8%)	General and administrative	28		84		(67%)	89		172		(48%)
Depreciation and amortization		1,918			1,913		0%		5,765			5,744		0%	Depreciation and amortization	1,928		1,920		—	3,854		3,847		—
Gain on asset sales, net		(9	)		—		*		(35	)		—		*	Gain on asset sales, net	—		(42)		*	—		(26)		*
Total costs and expenses		2,836			2,909		(3%)		8,527			8,984		(5%)	Total costs and expenses	2,614		2,719		(4%)	5,379		5,691		(5%)
Add:															Add:
Depreciation and amortization		1,918			1,913				5,765			5,744			Depreciation and amortization	1,928		1,920			3,854		3,847
Adjustments related to capital reimbursement activity		(5	)		(5	)			(14	)		(14	)		Adjustments related to capital reimbursement activity	(11)		(4)			(23)		(9)
Gain on asset sales, net		(9	)		—				(35	)		—			Gain on asset sales, net	—		(42)			—		(26)
Segment adjusted EBITDA	$	7,453		$	7,864		(5%)	$	24,074		$	20,697		16%	Segment adjusted EBITDA	$	10,652	$	10,693	0%	$	18,372	$	16,621	11%


	Williston Basin															Williston Basin
	Three months ended September 30,							Nine months ended September 30,								Three Months Ended June 30,					Six Months Ended June 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)															(Dollars in thousands)					(Dollars in thousands)
Revenues:															Revenues:
Gathering services and related fees	$	10,941		$	16,685		(34%)	$	47,145		$	58,076		(19%)	Gathering services and related fees	$	12,516	$	12,407	1%	$	25,149	$	36,204	(31%)
Natural gas, NGLs and condensate sales		4,957			1,878		164%		12,412			11,231		11%	Natural gas, NGLs and condensate sales	8,201		3,131		162%	20,428		7,455		174%
Other revenues		3,137			2,555		23%		9,055			8,133		11%	Other revenues	4,242		2,776		53%	8,749		5,918		48%
Total revenues		19,035			21,118		(10%)		68,612			77,440		(11%)	Total revenues	24,959		18,314		36%	54,326		49,577		10%
Costs and expenses:															Costs and expenses:
Cost of natural gas and NGLs		2,968			(93	)	(3291%)		5,572			3,668		52%	Cost of natural gas and NGLs	8,548		941		808%	20,873		2,604		702%
Operation and maintenance		5,658			8,578		(34%)		18,207			20,800		(12%)	Operation and maintenance	5,483		5,827		(6%)	10,407		12,549		(17%)
General and administrative		351			405		(13%)		1,381			1,117		24%	General and administrative	332		492		(33%)	686		1,030		(33%)
Depreciation and amortization		6,481			4,788		35%		19,463			14,958		30%	Depreciation and amortization	5,915		6,487		(9%)	11,837		12,982		(9%)
(Gain) loss on asset sales, net		(12	)		1		*		(50	)		(1,142	)	*
Gain on asset sales, net															Gain on asset sales, net	—		(96)		*	(15)		(47)		*
Long-lived asset impairment		—			—		*		—			18		*	Long-lived asset impairment	41		9		*	41		9		*
Total costs and expenses		15,446			13,679		13%		44,573			39,419		13%	Total costs and expenses	20,319		13,660		49%	43,829		29,127		50%
Add:															Add:
Depreciation and amortization		6,481			4,788				19,463			14,958			Depreciation and amortization	5,915		6,487			11,837		12,982
Adjustments related to MVC shortfall payments		2,125			2,081				(1,416	)		(1,387	)		Adjustments related to MVC shortfall payments	—		2,124			—		(3,541)
Adjustments related to capital reimbursement activity		(470	)		(469	)			(1,404	)		(1,244	)		Adjustments related to capital reimbursement activity	(970)		(451)			(1,929)		(934)
(Gain) loss on asset sales, net		(12	)		1				(50	)		(1,142	)
Gain on asset sales, net															Gain on asset sales, net	—		(96)			(15)		(47)
Long-lived asset impairment		—			—				—			18			Long-lived asset impairment	41		9			41		9
Segment adjusted EBITDA	$	11,713		$	13,840		(15%)	$	40,632		$	49,224		(17%)	Segment adjusted EBITDA	$	9,626	$	12,727	(24%)	$	20,431	$	28,919	(29%)

~~decreased$8.6 millioncompared to the nine months ended September 30, 2019 primarily reflecting:~~

•

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

~~Other items to note:~~

•

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

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

DJ Basin

Three months ended September 30,

Nine months ended September 30,

2020

2019

Percentage
Change

2020

2019

Percentage
Change
Average daily throughput
(MMcf/d)

27

33

(18%)

26

25

4%


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

Volume throughput increased compared to the ~~nine~~three months ended ~~September~~June 30, ~~2019,~~2020, and increased compared to the six months ended June 30, 2020, 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 and ~~temporary~~a decreased number of wells that were commissioned during 2021, together with temporarily shut-in production ~~curtailments associated with a significant reduction~~that our customers initiated in ~~crude oil prices as a result of a decrease in demand attributable to~~ the ~~COVID-19 pandemic.~~

prior-year period.

Financial data for our DJ Basin reportable segment follows.


	DJ Basin											DJ Basin
	Three months ended September 30,					Nine months ended September 30,						Three Months Ended June 30,					Six Months Ended June 30,
	2020		2019		Percentage Change	2020		2019		Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)											(Dollars in thousands)					(Dollars in thousands)
Revenues:											Revenues:
Gathering services and related fees	$	6,051	$	7,039	(14%)	$	18,134	$	14,784	23%	Gathering services and related fees	$	5,891	$	5,228	13%	$	12,154	$	12,083	1%
Natural gas, NGLs and condensate sales		17		93	(82%)		158		279	(43%)	Natural gas, NGLs and condensate sales	305		71		330%	415		141		194%
Other revenues		826		735	12%		2,853		2,776	3%	Other revenues	1,856		993		87%	2,560		2,027		26%
Total revenues		6,894		7,867	(12%)		21,145		17,839	19%	Total revenues	8,052		6,292		28%	15,129		14,251		6%
Costs and expenses:											Costs and expenses:
Cost of natural gas and NGLs		46		11	*		57		21	*	Cost of natural gas and NGLs	214		2		*	230		11		*
Operation and maintenance		2,352		1,781	32%		7,222		5,658	28%	Operation and maintenance	1,882		2,354		(20%)	3,794		4,870		(22%)
General and administrative		245		54	354%		468		186	152%	General and administrative	1,350		141		857%	1,669		223		648%
Depreciation and amortization		1,558		775	101%		4,587		2,038	125%	Depreciation and amortization	1,544		1,502		3%	3,096		3,029		2%
Loss on asset sales, net		—		—	*		20		—	*
(Gain) loss on asset sales, net											(Gain) loss on asset sales, net	(5)		20		*	(7)		20		*
Long-lived asset impairment		—		—	*		3,692		34,759	*	Long-lived asset impairment	—		57		*	95		3,692		*
Total costs and expenses		4,201		2,621	60%		16,046		42,662	(62%)	Total costs and expenses	4,985		4,076		—	8,877		11,845		(25%)
Add:											Add:
Depreciation and amortization		1,558		775			4,587		2,038		Depreciation and amortization	1,544		1,502			3,096		3,029
Adjustments related to capital reimbursement activity		515		533			1,618		69		Adjustments related to capital reimbursement activity	500		544			994		1,103
Loss on asset sales, net		—		—			20		—
(Gain) loss on asset sales, net											(Gain) loss on asset sales, net	(5)		20			(7)		20
Long-lived asset impairment		—		—			3,692		34,759		Long-lived asset impairment	—		57			95		3,692
Other											Other	—		—			23		—
Segment adjusted EBITDA	$	4,766	$	6,554	(27%)	$	15,016	$	12,043	25%	Segment adjusted EBITDA	$	5,106	$	4,339	18%	$	10,453	$	10,250	2%

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


	Permian Basin												Permian Basin
	Three months ended September 30,					Nine months ended September 30,							Three Months Ended June 30,					Six Months Ended June 30,
	2020		2019		Percentage Change	2020		2019			Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(In thousands)												(Dollars in thousands)					(Dollars in thousands)
Revenues:												Revenues:
Gathering services and related fees	$	2,595	$	986	163%	$	7,617	$	1,938		293%	Gathering services and related fees	$	2,262	$	2,711	(17%)	$	4,461	$	5,022	(11%)
Natural gas, NGLs and condensate sales		4,803		3,797	26%		13,537		10,424		30%	Natural gas, NGLs and condensate sales	6,875		4,222		63%	13,393		8,734		53%
Other revenues		168		102	65%		481		183		163%	Other revenues	121		126		(4%)	237		313		(24%)
Total revenues		7,566		4,885	55%		21,635		12,545		72%	Total revenues	9,258		7,059		31%	18,091		14,069		29%
Costs and expenses:												Costs and expenses:
Cost of natural gas and NGLs		4,958		3,242	53%		12,798		9,369		37%	Cost of natural gas and NGLs	7,167		3,691		94%	14,182		7,840		81%
Operation and maintenance		1,658		1,338	24%		4,301		3,962		9%	Operation and maintenance	1,527		1,456		5%	2,519		2,643		(5%)
General and administrative		57		95	(40%)		234		210		11%	General and administrative	118		84		40%	235		177		33%
Depreciation and amortization		1,370		1,312	4%		4,102		3,547		16%	Depreciation and amortization	1,464		1,387		6%	2,933		2,732		7%
(Gain) loss on asset sales, net		14		—	*		1		(120	)	*
Gain on asset sales, net												Gain on asset sales, net	—		(17)		*	—		(13)		*
Long-lived asset impairment		—		—	*		182		8		*	Long-lived asset impairment	—		—			—		182		*
Total costs and expenses		8,057		5,987	35%		21,618		16,976		27%	Total costs and expenses	10,276		6,601		56%	19,869		13,561		47%
Add:												Add:
Depreciation and amortization		1,370		1,312			4,102		3,547			Depreciation and amortization	1,464		1,387			2,933		2,732
(Gain) loss on asset sales, net		14		—			1		(120	)
Gain on asset sales, net												Gain on asset sales, net	—		(17)			—		(13)
Long-lived asset impairment		—		—			182		8			Long-lived asset impairment	—		—			—		182
Other												Other	15		—			15		—
Segment adjusted EBITDA	$	893	$	210	*	$	4,302	$	(996	)	*	Segment adjusted EBITDA	$	461	$	1,828	(75)%	$	1,170	$	3,409	(66)%


	Piceance Basin															Piceance Basin
	Three months ended September 30,							Nine months ended September 30,								Three Months Ended June 30,					Six Months Ended June 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)															(Dollars in thousands)					(Dollars in thousands)
Revenues:															Revenues:
Gathering services and related fees	$	26,576		$	30,120		(12%)	$	79,987		$	92,515		(14%)	Gathering services and related fees	$	25,527	$	26,222	(3%)	$	50,311	$	53,411	(6%)
Natural gas, NGLs and condensate sales		528			1,733		(70%)		1,932			6,139		(69%)	Natural gas, NGLs and condensate sales	1,025		401		156%	2,878		1,404		105%
Other revenues		1,233			1,258		(2%)		3,394			3,341		2%	Other revenues	1,233		1,096		13%	2,409		2,161		11%
Total revenues		28,337			33,111		(14%)		85,313			101,995		(16%)	Total revenues	27,785		27,719		0%	55,598		56,976		(2%)
Costs and expenses:															Costs and expenses:
Cost of natural gas and NGLs		399			1,502		(73%)		1,176			4,255		(72%)	Cost of natural gas and NGLs	697		320		118%	1,816		777		134%
Operation and maintenance		6,073			7,273		(16%)		16,278			21,680		(25%)	Operation and maintenance	5,367		5,267		2%	10,309		10,205		1%
General and administrative		196			128		53%		757			724		5%	General and administrative	345		276		25%	643		561		15%
Depreciation and amortization		11,305			11,798		(4%)		33,909			35,399		(4%)	Depreciation and amortization	10,757		11,306		(5%)	21,631		22,604		(4%)
(Gain) loss on asset sales, net		(94	)		—		*		(190	)		3		*	(Gain) loss on asset sales, net	4		(83)		*	(53)		(96)		*
Long-lived asset impairment															Long-lived asset impairment	—		—		*	970		—		*
Total costs and expenses		17,879			20,701		(14%)		51,930			62,061		(16%)	Total costs and expenses	17,170		17,086		0%	35,316		34,051		4%
Add:															Add:
Depreciation and amortization		11,305			11,798				33,909			35,399			Depreciation and amortization	10,757		11,306			21,631		22,604
Adjustments related to MVC shortfall payments		167			—				557			(103	)		Adjustments related to MVC shortfall payments	—		167			—		390
Adjustments related to capital reimbursement activity		(333	)		(164	)			(865	)		(606	)		Adjustments related to capital reimbursement activity	(1,403)		(289)			(1,831)		(532)
(Gain) loss on asset sales, net		(94	)		—				(190	)		3			(Gain) loss on asset sales, net	4		(83)			(53)		(96)
Long-lived asset impairment															Long-lived asset impairment	—		—			970		—
Other															Other	351		—			359		—
Segment adjusted EBITDA	$	21,503		$	24,044		(11%)	$	66,794		$	74,627		(10%)	Segment adjusted EBITDA	$	20,324	$	21,734	(6%)	$	41,358	$	45,291	(9%)


	Barnett Shale															Barnett Shale
	Three months ended September 30,							Nine months ended September 30,								Three Months Ended June 30,					Six Months Ended June 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)															(Dollars in thousands)					(Dollars in thousands)
Revenues:															Revenues:
Gathering services and related fees	$	10,545		$	11,286		(7%)	$	30,865		$	35,739		(14%)	Gathering services and related fees	$	10,076	$	9,877	2%	$	19,772	$	20,320	(3%)
Natural gas, NGLs and condensate sales		477			4,828		(90%)		7,206			11,705		(38%)	Natural gas, NGLs and condensate sales	10		2,858		(100%)	66		6,729		(99%)
Other revenues (1)		1,399			1,706		(18%)		4,437			5,008		(11%)	Other revenues (1)	1,012		1,778		(43%)	2,072		3,038		(32%)
Total revenues		12,421			17,820		(30%)		42,508			52,452		(19%)	Total revenues	11,098		14,513		(24%)	21,910		30,087		(27%)
Costs and expenses:															Costs and expenses:
Cost of natural gas and NGLs		261			2,810		(91%)		3,342			7,384		(55%)	Cost of natural gas and NGLs	—		1,134		(100%)	—		3,081		(100%)
Operation and maintenance		4,810			5,567		(14%)		14,069			16,181		(13%)	Operation and maintenance	1,852		4,564		(59%)	4,316		9,259		(53%)
General and administrative		351			201		75%		1,242			667		86%	General and administrative	260		513		(49%)	495		891		(44%)
Depreciation and amortization		3,795			3,810		(0%)		11,380			11,555		(2%)	Depreciation and amortization	3,798		3,788		—	7,596		7,585		—
(Gain) loss on asset sales, net		—			(350	)	*		17			(343	)	*	(Gain) loss on asset sales, net	(11)		(42)		*	(11)		17		*
Long-lived asset impairment		—			—		*		4			10,236		*	Long-lived asset impairment	—		—		*	289		4		*
Total costs and expenses		9,217			12,038		(23%)		30,054			45,680		(34%)	Total costs and expenses	5,899		9,957		(41%)	12,685		20,837		(39%)
Add:															Add:
Depreciation and amortization		4,030			4,045				12,085			12,542			Depreciation and amortization	4,032		4,023			8,064		8,055
Adjustments related to MVC shortfall payments		—			1,453				—			4,358
Adjustments related to capital reimbursement activity		(29	)		(29	)			(85	)		(82	)		Adjustments related to capital reimbursement activity	(331)		(27)			(662)		(56)
(Gain) loss on asset sales, net		—			(350	)			17			(343	)		(Gain) loss on asset sales, net	(11)		(42)			(11)		17
Long-lived asset impairment		—			—				4			10,236			Long-lived asset impairment	—		—			289		4

Segment adjusted EBITDA	$	7,205		$	10,901		(34%)	$	24,475		$	33,483		(27%)	Segment adjusted EBITDA	$	8,889	$	8,510	4%	$	16,905	$	17,270	(2)%


	Marcellus Shale															Marcellus Shale
	Three months ended September 30,							Nine months ended September 30,								Three Months Ended June 30,					Six Months Ended June 30,
	2020			2019			Percentage Change	2020			2019			Percentage Change		2021		2020		Percentage Change	2021		2020		Percentage Change
	(Dollars in thousands)															(Dollars in thousands)					(Dollars in thousands)
Revenues:															Revenues:
Gathering services and related fees	$	6,871		$	5,987		15%	$	19,034		$	18,081		5%	Gathering services and related fees	$	6,612	$	5,928	12%	$	12,813	$	12,163	5%
Total revenues		6,871			5,987		15%		19,034			18,081		5%	Total revenues	6,612		5,928		12%	12,813		12,163		5%
Costs and expenses:															Costs and expenses:
Operation and maintenance		771			783		(2%)		2,517			2,892		(13%)	Operation and maintenance	658		933		(29%)	1,160		1,746		(34%)
General and administrative		69			237		(71%)		259			426		(39%)	General and administrative	76		97		(22%)	165		190		(13%)
Depreciation and amortization		2,298			2,286		1%		6,898			6,855		1%	Depreciation and amortization	2,301		2,300		0%	4,605		4,600		0%
Gain on asset sales, net		(8	)		—		*		(8	)		—		*
Goodwill impairment		—			16,211		*		—			16,211		*
(Gain) loss on asset sales, net															(Gain) loss on asset sales, net	8		—		*	(54)		—		*
Long-lived asset impairment															Long-lived asset impairment	(8)		—		*	130		—		*
Total costs and expenses		3,130			19,517		(84%)		9,666			26,384		(63%)	Total costs and expenses	3,035		3,330		(9%)	6,006		6,536		(8%)
Add:															Add:
Depreciation and amortization		2,298			2,286				6,898			6,855			Depreciation and amortization	2,301		2,300			4,605		4,600
Goodwill impairment		—			16,211				—			16,211
Adjustments related to capital reimbursement activity		(9	)		(9	)			(28	)		(28	)		Adjustments related to capital reimbursement activity	(10)		(10)			(19)		(19)
Gain on asset sales, net		(8	)		—				(8	)		—
(Gain) loss on asset sales, net															(Gain) loss on asset sales, net	8		—			(54)		—
Long-lived asset impairment															Long-lived asset impairment	(8)		—			130		—
Segment adjusted EBITDA	$	6,022		$	4,958		21%	$	16,230		$	14,735		10%	Segment adjusted EBITDA	$	5,868	$	4,888	20%	$	11,469	$	10,208	12%

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

~~Summarized Financial Information~~

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

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

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

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

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

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

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

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

September 30, 2020

SMLP

Obligor Group

(In thousands)

Assets

Current assets

$
5,719

$
124,603

Noncurrent assets

7,886

2,308,461

Liabilities

Current liabilities

$
10,173

$
60,721

Noncurrent liabilities

2,931

1,438,929

December 31, 2019

SMLP

Obligor Group

(In thousands)

Assets

Current assets

$
7,396

$
104,964

Noncurrent assets

9,835

2,389,032

Liabilities

Current liabilities

$
14,527

$
69,177

Noncurrent liabilities

163,163

1,514,250

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

Nine months ended September 30, 2020

SMLP

Obligor Group

(In thousands)

Total revenues

$
—

$
287,063

Total costs and expenses

5,289

216,715

(Loss) income before income taxes and income from
equity method investees

(5,120
)

95,818

Income from equity method investees

—

8,498

Net (loss) income

$
(6,612
)

$
104,316

Year ended December 31, 2019

SMLP

Obligor Group

(In thousands)

Total revenues

$
—

$
443,528

Total costs and expenses

8,719

397,939

Loss before income taxes and loss from
equity method investees

(25,805
)

(28,840
)
Loss from equity method investees (1)

—

(336,950
)
Net loss

$
(27,036
)

$
(365,790
)

~~(1)~~

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

Liquidity and Capital Resources

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

•

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

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

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

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

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

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

~~other changes in working capital.~~

•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 ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 primarily reflected:

•

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

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

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

•$6.0 million cash outflow for capital expenditures;

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

Cash flows used in investing activities during the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 primarily reflected:

•

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

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

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

•$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.

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

•

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

Financing activities.

Cash flows used in financing activities during the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 primarily reflected:

•

~~$165.5 millionof borrowings under our Revolving Credit Facility;~~

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

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

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

~~$35.0 millionof net borrowings under ECP Loans;~~

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

~~$82.8 million for Open Market Repurchases;~~

•

~~$48.7 million for Tender Offers;~~

•

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

•

~~$35.0 million for the repayment of ECP Loans;~~

•

~~$34.0 million for repayments under our Revolving Credit Facility;~~

•

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

•

~~$6.0 millionof distributionsto noncontrolling interest SMLP unitholders.~~

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

•

~~$149.7 million of distributions; and~~

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

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

•

~~$131.0 million for repayments under our Revolving Credit Facility.~~

Table of Contents

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

•$35.0 million of net borrowings under ECP Loans;

•$76.7 million repurchase of Senior Notes;

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

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

Contractual Obligations Update

~~Double E Project~~

We are leading the development, permitting and construction of the Double E Project and will operate the pipeline upon its commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately ~~$300~~$300.0 million. Assuming timely receipt of the required regulatory approvals and no material delays in construction, we expect that the Double E Project will be placed into service in the fourth quarter of 2021.

On March 8, 2021, we entered into the Permian Transmission Credit Facility to finance the vast majority of our remaining capital calls associated with the Double E Project, debt services and other general corporate purposes.

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

Capital Requirements

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

•

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

•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.

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

For the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, cash paid for capital expenditures totaled~~$35.3~~ $6.0 million ~~and~~which included ~~$11.0~~$2.1 millionof maintenance capital expenditures. For the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, there were no contributions to Ohio Gathering and we contributed ~~$92.1~~$48.9 million to Double E (see Note 65 – Equity Method Investments).

We expect 2021 total capital expenditures to range from $20.0 million to $35.0 million.

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

Our Revolving Credit Facility became current on May 13, 2021. We are in the process of negotiating the ABL Revolver that will be conditioned on the High Yield Notes Offering. It is our goal to consummate both financings concurrently during the quarter ending September 30, 2021. The proceeds of the ABL Revolver and the High Yield Notes Offering would be used to repay the Revolving Credit Facility and redeem the 2022 Senior Notes.However, there can be no assurance that we will be able to arrange an ABL Revolver or consummate the High Yield Notes Offering on terms acceptable to us prior to September 30, 2021 or at all.

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

Table of ~~our Double E capital commitments to third parties.~~

Contents

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

markets.

Credit and Counterparty Concentration Risks

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

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

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

Off-Balance Sheet Arrangements

~~We had~~

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

Summarized Financial Information

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

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

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

Table of Contents


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

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


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

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

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

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


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


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

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no changes to our significant accounting policies since December 31, ~~2019.~~

2020.

Table of Contents

Forward-Looking Statements

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

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

•

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•the ability to attract and retain key management personnel;

~~the ability to attract and retain key management personnel;~~

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

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

•changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets;

~~changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets;~~

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

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

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

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

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

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

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

•

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

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

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

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

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

•

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

Table of Contents

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

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

•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;

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

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

~~the ability to meet obligations under the SMPH Term Loan;~~

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

~~changes in tax status;~~

•changes in tax status;

~~the effects of litigation;~~

•the effects of litigation;

~~changes in general economic conditions; and~~

•changes in general economic conditions; and

~~certain factors discussed elsewhere in this report.~~

•certain factors discussed elsewhere in this report.

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

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

Information About Us

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

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

Table of Contents

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.~~indebtedness. As of ~~September~~June 30, ~~2020,~~2021, we had approximately ~~$589.1~~$493.5 million principal of fixed-rate Senior Notes, ~~$808.5~~$762.0 millionoutstanding under our variable rate Revolving Credit Facility and ~~$155.2~~$53.5 million ~~principal of~~outstanding under the variable rate ~~debt on the SMPH Term Loan~~Permian Transmission Credit Facility (see Note 87 - Debt). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, ~~2019.~~2020. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the ~~2019~~2020 Annual Report.

Commodity Price Risk

We ~~currently~~ generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, ~~some~~many of which include MVCs and ~~most of which include~~ areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers onin the ~~Bison Midstream, Grand River~~Williston Basin, Piceance Basin, and ~~Summit~~ Permian ~~systems,~~Basin segments, (ii) the sale of natural gas we retain from certain ~~DFW Midstream~~Barnett Shale segment customers and (iii) the sale of condensate we retain from ~~our~~certain gathering services ~~at Grand River.~~in the Piceance Basin segment. Our gathering agreements with certain ~~DFW Midstream~~Barnett Shale customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. ~~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 price or heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 ~~Index.~~Index or pass through actual power expense to our customers, per the terms of each individual customer. By basing the power prices on a system and basin-relevant market, ~~like the Henry Hub Index,~~ we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. Our current commodity price risk exposure has not changed materially since December 31, ~~2019.~~2020. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the ~~2019~~2020 Annual Report.

Item 4. Controls and Procedures.

Under the direction of our General Partner's Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2020~~2021 and (ii) no change in internal control over financial reporting occurred during the quarter ended ~~September~~June 30, ~~2020,~~2021, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

On August 4, 2021, certain subsidiaries of the Partnership entered into agreements to resolve government investigations into the previously disclosed discovery in ~~Note 14 – Commitments~~January 2015 of a release of produced water into Blacktail Creek, near Marmon, North Dakota (“2015 Blacktail Release”), from a pipeline owned and ~~Contingencies~~operated by Meadowlark Midstream Company, LLC (“Meadowlark”), which at the time was a wholly owned subsidiary of Summit Midstream Partners, LLC (“Summit Investments,” together with Meadowlark, the “Companies”). The Companies have entered into the following agreements to resolve the U.S. federal and North Dakota state governments’ environmental claims against the Companies with respect to the 2015 Blacktail Release: (i) a Consent Decree with (a) the U.S. Department of Justice (“DOJ”), on behalf of the U.S. Environmental Protection Agency and the U.S. Department of Interior, and (b) the State of North Dakota, on behalf of the North Dakota Department of Environmental Quality and the North Dakota Game and Fish Department (“Consent Decree”), to be lodged with the U.S. District Court for the District of North Dakota (“U.S. District Court”); (ii) a Plea Agreement with the United States, by and through the U.S. Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ (“Plea Agreement”); and (iii) a Consent Agreement with the North Dakota Industrial Commission ("Consent Agreement" together with the Consent Decree and Plea Agreement, the “Global Settlement”), to be filed with the U.S. District Court.

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

Under the Plea Agreement, the Companies agreed to, among other requirements and subject to the conditions therein, (i) enter guilty pleas for one charge of negligent discharge of a harmful quantity of oil and one charge of knowing failure to immediately report a discharge of oil; (ii) sentencing that includes payment of a fine of $15.0 million plus mandatory special assessments over a period of up to five years with interest accruing at the federal statutory rate; (iii) organizational probation for a minimum period of three years from sentencing, which will include payment in full of certain components of the fines and penalty amounts; and (iv) compliance with the remedial measures in the ~~2019 Annual~~Consent Decree. The Plea Agreement is subject to the approval of the U.S. District Court.

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

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

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

reference herein.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of the ~~2019~~2020 Annual Report the Item 1A. Risk Factors of our quarterly report on Form 10-Q for the three months ended March 31, 2020, as filed with the SEC on May 8, 2020, and the Item 1A. Risk Factors of our quarterly report on Form 10-Q for the three months ended June 30, 2020, as filed with the SEC on August 7, 2020 are incorporated herein by reference except to the extent they address risks arising from or relating to the failure of events described therein to occur, which events have since occurred.

~~Risks Relating~~ The risk factors presented below are an update to, ~~COVID-19~~

~~The COVID-19 pandemic, coupled with~~and should be considered in addition to, the risk factors previously disclosed by us in our 2020 Annual Report.

Table of Contents

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other ~~current pressures on oil and gas prices resulting from~~actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful. Because the ~~OPEC price war, has had, and~~maturity date of our Revolving Credit Facility is ~~expected~~within twelve months of the date that these financial statements were issued, there is substantial doubt about our ability to continue as a going concern.

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

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

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

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior secured or unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates, may require the pledging of collateral and may require us to comply with more onerous covenants than we are currently subject to, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations ~~financial position~~to meet our debt service and ~~cash flows.~~

~~The ongoing coronavirus (COVID-19) outbreak continues~~other obligations. Our Revolving Credit Facility and the indentures governing our Senior Notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.

Further, if for any reason we are unable to meet our debt service and principal repayment obligations, or if we fail to comply with the leverage ratios in the documents governing our debt, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be ~~a rapidly evolving situation. As of November 3, 2020,~~due and payable (which would in turn trigger cross-acceleration or cross-default rights among our debt agreements), the ~~CDC had recorded over 9.2 million cases in the United States and over 230,000 deaths,~~lenders under our Revolving Credit Facility could terminate their commitments to extend credit, and the ~~pandemic has resulted in a massive increase in~~lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the ~~U.S. unemployment rate. The pandemic has resulted in widespread adverse impacts on the global economy and on~~amounts outstanding under our ~~business, including~~Revolving Credit Facility or 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 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 determineSenior Notes were to be ~~in the best interests of~~accelerated, we cannot assure you that our ~~employees, customers, partners and suppliers. There is no certainty that such measures will~~assets would be sufficient to ~~mitigate~~repay in full the ~~risks posed by the virus, in which case~~amounts owed to our ~~employees may become sick, our ability to perform critical functions could be harmed, and we may be unable to respond to the needs~~creditors.

The tax treatment of ~~our business. The resumption of normal business operations after such interruptions may be delayed~~publicly traded partnerships or ~~constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.~~

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

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

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

~~Risks Related to Our Business~~

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

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

~~If we fail to regain compliance with Section 802.01C of the NYSE Listed Company Manual by the end of the cure period, the common units will~~ be subject to ~~the NYSE’s suspension~~potential legislative, judicial or administrative changes and ~~delisting procedures. If the common~~differing interpretations of applicable law, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units ~~ultimately were~~may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to ~~be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price~~time, members of the ~~common units, reduce the number of investors willing to hold or acquire the common units~~U.S. Congress propose and ~~negatively impact our ability to access equity markets and obtain financing.~~

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

~~The Series A Preferred Units rank senior~~existing federal income tax laws that affect publicly traded partnerships.

Any modification to ~~our common units with respect to distribution rights~~the U.S. federal income tax laws and ~~rights upon liquidation. These preferences could adversely affect the market price for our common units or~~interpretations could make it more difficult or impossible to meet the exception 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 accumulatebe treated as a partnership for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%. On May 3, 2020, we announced the suspension of distributions payable on both our common units and our Series A Preferred Units. We did not make a distribution on our common units with respect to the first quarter of 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020. As of October 30, 2020, the amount of accrued and

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

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

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

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

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to an organization that is exempt fromU.S. federal income tax ~~including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return~~purposes. One recent proposal was contained in the ~~year~~Biden Administration’s budget proposal released on May 28, 2021, which would repeal the exempt organization is allocated the income. Under the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.

~~Under the Tax Reform Legislation, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0%~~application of the ~~amount realized by the transferor unless the transferor certifies that~~qualifying income exception to partnerships with income and gains from activities relating to fossil fuels for taxable years beginning after 2026. We are unable to predict whether any such changes will ultimately be enacted, but it is ~~not~~possible that a ~~foreign person,~~change in law could affect us and ~~we are required to deduct and withhold from~~may, if enacted, be applied retroactively. Any such changes could negatively impact the ~~transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury and the IRS have suspended these rules for transfers~~value of ~~certain publicly traded partnership interests, including transfers of~~an investment in our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022.

units.

Item 5. Other ~~Information.~~

~~None.~~

Information.

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

Table of Contents

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

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

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

Item 6. Exhibits.

~~Exhibit number~~	~~Description~~
~~3.1~~ Exhibit number			Description
3.1			Fourth Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.1 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))
3.2			Second Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed June 2, 2020 (Commission File No. 001-35666))
3.3			Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4			Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
10.1		+	Amendment to Warrants to Purchase Common Units, dated August 7, 2020, by and among Summit Midstream Partners, LP, SMP TopCo, LLC and SMLP Holdings, LLC (Incorporated herein by reference to Exhibit 10.11 to SMLP’s Quarterly Report on Form 10-Q dated August 7, 2020 (Commission File No. 001-34666))Joint Factual Statement
10.2		~~***~~ +	~~Transaction Support~~Criminal Plea Agreement dated September 29, 2020, by and among Summit Midstream Partners Holdings, LLC, Summit Midstream Partners, LLC, Summit Midstream Partners, LP and the Initial Directing Lenders listed therein (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated September 30, 2020 (Commission File No. 001-34666))
10.3		* +	~~Separation and General Release Agreement, effective as of August 7, 2020, by and between Summit Midstream Partners, LP and Brock Degeyter~~Consent Decree
~~10.4~~ 22.1		*	~~Employment Agreement, effective as of September 4, 2020, by and between Summit Midstream Partners, LP and James Johnston~~
~~22.1~~	Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities (Incorporated herein by reference to Exhibit 22.1 to SMLP's Report on Form 10-Q filed May 8, 2020 (Commission File No. 001-35666)
31.1		+	Rule 13a-14(a)/15d-14(a) Certification, executed by Heath Deneke, President, Chief Executive Officer and Director
31.2		+	Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, Executive Vice President and Chief Financial Officer
32.1		+	Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer
101.INS		**	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH		**	Inline XBRL Taxonomy Extension Schema
101.CAL		**	Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF		**	Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB		**	Inline XBRL Taxonomy Extension Label Linkbase
101.PRE		**	Inline XBRL Taxonomy Extension Presentation Linkbase
104		**	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

+ Filed herewith.

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

Table of Contents

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

*** Certain portions

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

Contents

SIGNATURES

~~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)
		~~(Registrant)~~

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

~~November~~August 6, ~~2020~~ 2021		/s/ ~~Marc~~MARC D. ~~Stratton~~ STRATTON

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


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

☒	~~Yes~~	☐
x			Yes			o			No

~~Class~~
Class						As of ~~October 30, 2020~~ August 1, 2021
Common Units						~~56,624,887~~6,744,926 units


COMMONLY USED OR DEFINED TERMS			2

PART I		FINANCIAL INFORMATION
Item 1.		Financial Statements.
		Unaudited Condensed Consolidated Balance Sheets.	45
		Unaudited Condensed Consolidated Statements of ~~Operations~~Operations..	56
		Unaudited Condensed Consolidated Statements of Partners' Capital.	67
		Unaudited Condensed Consolidated Statements of Cash Flows.	89
		Notes to Unaudited Condensed Consolidated Financial Statements.	910
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.	2524
Item 3.		Quantitative and Qualitative Disclosures about Market Risk.	5146
Item 4.		Controls and Procedures.	5246
PART II		OTHER INFORMATION	47
~~PART II~~Item 1.		~~OTHER INFORMATION~~Legal Proceedings.	5347
Item 1. 1A.		~~Legal Proceedings.~~Risk Factors.	5347
Item ~~1A.~~ 5.		Other Information~~Risk Factors.~~.	5348
Item 5. 6.		~~Other Information~~Exhibits..	5549
~~Item 6.~~		~~Exhibits.~~	56
SIGNATURES
~~SIGNATURES~~51	57

~~2016 Drop Down~~	~~the Partnership's March 3, 2016 acquisition from SMP Holdings of substantially all~~ ~~of (i) the issued and outstanding membership interests in Summit Utica,~~ ~~Meadowlark Midstream and Tioga Midstream and (ii) SMP Holdings’ 40%~~ ~~ownership interest in Ohio Gathering~~

2022 Senior Notes		Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
2025 Senior Notes		Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April 2025
~~associated natural gas~~		~~a form of natural gas which is found with deposits of petroleum, either dissolved~~ ~~in the crude oil or as a free gas cap above the crude oil in the reservoir~~
ASU		Accounting Standards Update
~~Bbl~~		~~one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons~~
~~Bcf~~	~~one billion cubic feet~~
Bison Midstream	Bison Midstream, LLC
Board of Directors		the board of directors of our General Partner
condensate		a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
~~Deferred Purchase Price~~ ~~Obligation~~		~~the deferred payment liability recognized in connection with the 2016 Drop Down, as~~ ~~subsequently amended, also known as the DPPO~~
DFW Midstream		DFW Midstream Services LLC
DJ Basin		Denver-Julesburg Basin
Double E		Double E Pipeline, LLC
Double E Project		the development and construction of a long-haul natural gas pipeline with an initial throughput capacity of 1.35 billion cubic feet per day that will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas
~~dry gas~~		~~natural gas primarily composed of methane where heavy hydrocarbons and water~~ ~~either do not exist or have been removed through processing or treating~~
~~Energy Capital Partners~~ Epping		~~Energy Capital Partners II, LLC and its parallel and co-investment funds~~
~~Epping~~	Epping Transmission Company, LLC
EPU		earnings or loss per unit
FASB		Financial Accounting Standards Board
Finance Corp.		Summit Midstream Finance Corp.
GAAP		accounting principles generally accepted in the United States of America
General Partner		Summit Midstream GP, LLC
GP		general partner
Grand River		Grand River Gathering, LLC
Guarantor Subsidiaries		Bison Midstream and its subsidiaries, Grand River and its subsidiaries, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, OpCo, Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer Midstream
~~LIBOR~~ hub		geographic location of a storage facility and multiple pipeline interconnections
LIBOR		London Interbank Offered Rate
~~Mbbl~~ Mbbl/d		~~one thousand barrels~~
~~Mbbl/d~~	one thousand barrels per day
~~Mcf~~		~~one thousand cubic feet~~
Meadowlark Midstream	Meadowlark Midstream Company, LLC
~~MMcf~~ MMcf/d		~~one million cubic feet~~
~~MMcf/d~~	one million cubic feet per day
Mountaineer Midstream		Mountaineer Midstream Company, LLC
MVC		minimum volume commitment
NGLs		natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from unprocessed natural gas streams become liquid under various levels of higher pressure and lower temperature
Niobrara G&P		Niobrara Gathering and Processing system
~~OCC~~ NYSE		New York Stock Exchange
OCC		Ohio Condensate Company, L.L.C.

☒
☒			QUARTERLY 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

OGC			Ohio Gathering Company, L.L.C.
Ohio Gathering			Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C.
OpCo			Summit Midstream OpCo, LP
play			a proven geological formation that contains commercial amounts of hydrocarbons
Permian Finance			Summit Midstream Permian Finance, LLC


Permian Holdco		Summit Permian Transmission Holdco, LLC
Permian Transmission Credit Facility		Credit Agreement, dated as of March 8, 2021, among Summit Permian Transmission, LLC, as borrower, MUFG Bank Ltd., as administrative agent, Mizuho Bank (USA), as collateral agent, ING Capital LLC, Mizuho Bank, Ltd. and MUFG Union Bank, N.A., as L/C issuers, coordinating lead arrangers and joint bookrunners, and the lenders from time to time party thereto
Polar and Divide		the Polar and Divide system; collectively Polar Midstream and Epping
~~Polar Midstream~~		~~Polar Midstream, LLC~~
produced water	water from underground geologic formations that is a by-product of natural gas and crude oil production
~~Red Rock Gathering~~		~~Red Rock Gathering Company, LLC~~
Revolving Credit Facility	the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as amended by the First Amendment to Third Amended and Restated Credit Agreement dated as of September 22, 2017, the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019, ~~and~~ the Third Amendment to Third Amended and Restated Credit Agreement dated as of December 24, 2019 and the Fourth Amendment to Third Amended and Restated Credit Agreement dated as of December 18, 2020
SEC		Securities and Exchange Commission
segment adjusted EBITDA		total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit- based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains
Senior Notes		The ~~2022~~5.5% Senior Notes and the ~~2025~~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, also known as SMPH
SMPH Term Loan		the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings, as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent
Subsidiary Series A Preferred Units		Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco
Summit Holdings		Summit Midstream Holdings, LLC
Summit Investments		Summit Midstream Partners, LLC
Summit Marketing		Summit Midstream Marketing, LLC
Summit Permian		Summit Midstream Permian, LLC
Summit Permian II		Summit Midstream Permian II, LLC
Summit Permian Transmission		Summit Permian Transmission, LLC
Summit Utica		Summit Midstream Utica, LLC
~~the Company~~		~~Summit Midstream Partners, LLC and its subsidiaries~~
the Partnership	Summit Midstream Partners, LP and its subsidiaries
the Partnership Agreement		the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership dated May 28, 2020
throughput volume		the volume of natural gas, crude oil or produced water gathered, transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput


~~Tioga Midstream~~		~~Tioga Midstream, LLC~~
unconventional resource basin	a basin where natural gas or crude oil production is developed from unconventional sources that require hydraulic fracturing as part of the completion process, for instance, natural gas produced from shale formations and coalbeds; also referred to as an unconventional resource play
wellhead		the equipment at the surface of a well, used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground


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

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

	Three months ended September 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	8,385	$	0	$	0	$	8,385
Williston Basin		10,941		4,958		3,136		19,035
DJ Basin		6,051		17		826		6,894
Permian Basin		2,595		4,803		168		7,566
Piceance Basin		26,576		528		1,233		28,337
Barnett Shale		10,545		477		1,399		12,421
Marcellus Shale		6,871		0		0		6,871
Total reportable segments		71,964		10,783		6,762		89,509
All other segments		0		0		644		644
Total	$	71,964	$	10,783	$	7,406	$	90,153

	Three months ended September 30, 2019
	Gathering services and related fees		Natural gas, NGLs and condensate sales			Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	8,865	$	0		$	0	$	8,865
Williston Basin		16,685		1,878			2,555		21,118
DJ Basin		7,039		93			735		7,867
Permian Basin		986		3,797			102		4,885
Piceance Basin		30,120		1,733			1,258		33,111
Barnett Shale		11,286		4,828			1,706		17,820
Marcellus Shale		5,987		0			0		5,987
Total reportable segments		80,968		12,329			6,356		99,653
All other segments		0		(110	)		644		534
Total	$	80,968	$	12,219		$	7,000	$	100,187

	Nine months ended September 30, 2019
	Gathering services and related fees			Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	23,951		$	0	$	0	$	23,951
Williston Basin		58,076			11,231		8,133		77,440
DJ Basin		14,784			279		2,776		17,839
Permian Basin		1,938			10,424		183		12,545
Piceance Basin		92,515			6,139		3,341		101,995
Barnett Shale		35,739			11,705		5,008		52,452
Marcellus Shale		18,081			0		0		18,081
Total reportable segments		245,084			39,778		19,441		304,303
All other segments		(2,045	)		28,660		363		26,978
Total	$	243,039		$	68,438	$	19,804	$	331,281


	Three Months Ended June 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	11,538	$	0	$	0	$	11,538
Williston Basin	12,407		3,131		2,776		18,314
DJ Basin	5,228		71		993		6,292
Permian Basin	2,711		4,222		126		7,059
Piceance Basin	26,222		401		1,096		27,719
Barnett Shale	9,877		2,858		1,778		14,513
Marcellus Shale	5,928		0		0		5,928
Total reportable segments	73,911		10,683		6,769		91,363
Corporate and Other	0		0		644		644
Total	$	73,911	$	10,683	$	7,413	$	92,007


	Six Months Ended June 30, 2020
	Gathering services and related fees		Natural gas, NGLs and condensate sales		Other revenues		Total
	(in thousands)
Reportable Segments:
Utica Shale	$	18,500	$	0	$	0	$	18,500
Williston Basin	36,204		7,455		5,918		49,577
DJ Basin	12,083		141		2,027		14,251
Permian Basin	5,022		8,734		313		14,069
Piceance Basin	53,411		1,404		2,161		56,976
Barnett Shale	20,320		6,729		3,038		30,087
Marcellus Shale	12,163		0		0		12,163
Total reportable segments	157,703		24,463		13,457		195,623
Corporate and Other	0		0		1,287		1,287
Total	$	157,703	$	24,463	$	14,744	$	196,910

	September 30, 2020
	(In thousands)
Contract assets, January 1, 2020	$	3,902
Additions		16,442
Transfers out		(2,275	)
Contract assets, September 30, 2020	$	18,069


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


	September 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
	(In thousands)					(In thousands)
Gathering and processing systems and related equipment	$	2,197,087	$	2,182,950	Gathering and processing systems and related equipment	$	2,221,834	$	2,213,501
Construction in progress		78,146		78,716	Construction in progress	45,780		60,443
Land and line fill		10,440		10,137	Land and line fill	10,440		10,440
Other		60,589		54,595	Other	59,683		61,340
Total		2,346,262		2,326,398	Total	2,337,737		2,345,724
Less accumulated depreciation		(505,978)		(443,909)
Less: accumulated depreciation					Less: accumulated depreciation	(568,840)		(528,178)
Property, plant and equipment, net	$	1,840,284	$	1,882,489	Property, plant and equipment, net	$	1,768,897	$	1,817,546


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

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

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

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

	ECP Loan Repayment			Open Market Repurchases						Tender Offers						Total
				2022			2025			2022			2025							Open Market Repurchases During the Six Months Ended June 30, 2020				Total
				Senior Notes			Senior Notes			Senior Notes			Senior Notes							2022		2025
	(in thousands)																			Senior Notes		Senior Notes
Gain on repurchases of Senior Notes	$	-		$	11,554		$	46,003		$	9,223		$	15,479		$	82,259		Gain on repurchases of Senior Notes	$	9,300	$	46,003		$	55,303
Debt issue costs		(361	)		(143	)		(965	)		(125	)		(351	)		(1,945	)	Debt issue costs	(117)		(951)			(1,068)
Transaction cost		(249	)		(105	)		(105	)		(465	)		(465	)		(1,389	)
Gain (loss) on extinguishment	$	(610	)	$	11,306		$	44,933		$	8,633		$	14,663		$	78,925

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

	~~Common Units~~
		Common Units
Units, December 31, ~~2019~~⁽¹⁾ 2020		6,110,092	~~45,318,866~~
~~Net~~2021 Preferred Exchange Offer, net of shares withheld for taxes		538,715
Common units issued ~~under the~~for SMLP LTIP, net		96,119	~~1,028,654~~
~~Impact of GP Buy-In Transaction~~ Units, June 30, 2021		6,744,926	~~(1,990,303~~	)
~~Preferred Unit Exchange~~		~~12,267,670~~
~~Units, September 30, 2020~~⁽¹⁾		~~56,624,887~~

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


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

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


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

	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	)