Summit Midstream Partners (SMLP) 8-K Other Events

P2YThe rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term used. Our incremental borrowing rate on the Revolving Credit Facility was 4.55% at December 31, 2019, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.P12M

EXHIBIT 99.3

EXPLANATORY NOTE

On May 28, 2020, Summit Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), closed on a Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company (“ECP”) to acquire all the outstanding limited liability company interests of Summit Midstream Partners, LLC, a Delaware limited liability company (“Summit Investments”). We refer to the transactions contemplated by the Purchase Agreement as the “GP

Buy-In

Transaction.”

The May 2020 acquisition of Summit Investments was a transaction between entities under common control. As a result, the Partnership recast its financial statements for the period that the entities were under common control by Summit Investments to retrospectively reflect the May 2020 acquisition. Under GAAP, the GP

Buy-In

Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results of the Partnership prior to the GP

Buy-In

Transaction presented below are those of Summit Investments. Prior to the GP

Buy-In

Transaction, Summit Investments controlled the Partnership and the Partnership’s financial statements were consolidated into Summit Investments.

The information in this Item 8. Financial Statements and Supplementary Data includes periods prior to the GP

Buy-In

Transaction. Consequently, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity for accounting purposes.

EX 99.3-1

Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm	EX 99.3-3
Consolidated Balance Sheets as of December 31, 2019 and 2018	EX 99.3-4
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	EX 99.3-5
Consolidated Statements of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017	EX 99.3-6
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	EX 99.3-7
Notes to Consolidated Financial Statements	EX 99.3-9
1. Organization, Business Operations and Presentation and Consolidation	EX 99.3-9
2. Summary of Significant Accounting Policies	EX 99.3-10
3. Revenue	EX 99.3-15
4. Segment Information	EX 99.3-17
5. Property, Plant and Equipment, Net	EX 99.3-21
6. Amortizing Intangible Assets	EX 99.3-23
7. Goodwill	EX 99.3-24
8. Equity Method Investments	EX 99.3-24
9. Deferred Revenue	EX 99.3-26
10. Debt	EX 99.3-28
11. Financial Instruments	EX 99.3-32
12. Partners’ Capital and Mezzanine Capital	EX 99.3-32
13. Earnings Per Unit	EX 99.3-35
14. Unit-Based and Noncash Compensation	EX 99.3-35
15. Related-Party Transactions	EX 99.3-36
16. Leases, Commitments and Contingencies	EX 99.3-37
17. Dispositions, Drop Down Transactions and Restructuring	EX 99.3-41
18. Unaudited Quarterly Financial Data	EX 99.3-42
19. Subsequent Events	EX 99.3-43

EX 99.3-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Summit Midstream GP, LLC and the unitholders of Summit Midstream Partners, LP Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2019 and 2018, the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, based on our audits and the report of the other auditors, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We did not audit the financial statements of Ohio Gathering Company, L.L.C. (“Ohio Gathering”) as of and for the years ended December 31, 2019, 2018, and 2017, the Partnership’s investment in which is accounted for by use of the equity method. The accompanying financial statements of the Partnership include its equity investment in Ohio Gathering of $275,000,000 and $642,036,000 as of December 31, 2019 and 2018, respectively, and its loss from equity method investee in Ohio Gathering of $329,736,000, $11,085,000, and $1,823,000 for the years ended December 31, 2019, 2018 and 2017, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ohio Gathering prior to the impairment loss discussed in Note 8, which was audited by us, is based solely on the report of the other auditors.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

March 9, 2020 (August 7, 2020 as to the retrospective adjustments to the financial statements for the common control transaction described in Notes 1 and 19)

We have served as the Partnership’s auditor since 2009.

EX 99.3-3

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31, 2019		December 31, 2018
		(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents		$	9,530	$	16,173
Restricted cash			27,392		—
Accounts receivable			97,418		97,936
Other current assets			5,521		4,388
Total current assets			139,861		118,497
Property, plant and equipment, net			1,882,489		1,964,099
Intangible assets, net			232,278		273,416
Goodwill			—		16,211
Investment in equity method investees			309,728		649,250
Other noncurrent assets			9,742		11,746
Total assets		$	2,574,098	$	3,033,219
Liabilities and Capital
Current liabilities:
Trade accounts payable		$	24,415	$	38,415
Accrued expenses			11,339		26,763
Deferred revenue			13,493		11,467
Ad valorem taxes payable			8,477		10,550
Accrued interest			12,346		12,339
Accrued environmental remediation			1,725		2,487
Other current liabilities	��		12,206		13,236
Current portion of long-term debt			5,546		14,500
Total current liabilities			89,547		129,757
Long-term debt			1,622,279		1,464,280
Noncurrent deferred revenue			38,709		39,504
Noncurrent accrued environmental remediation			2,926		3,149
Other noncurrent liabilities			7,951		4,962
Total liabilities			1,761,412		1,641,652
Commitments and contingencies (Note 16)
Mezzanine Capital
Subsidiary Series A Preferred Units (30,058 units issued and outstanding at December 31, 2019)			27,450		—
Partners’ Capital
Series A Preferred Units (300,000 units issued and outstanding at December 31, 2019 and December 31, 2018)			293,616		293,616
Common limited partner capital			305,550		543,479
Noncontrolling interest			186,070		554,472
Total partners’ capital			785,236		1,391,567
Total liabilities, mezzanine capital and partners’ capital		$	2,574,098	$	3,033,219

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

EX 99.3-4

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
	2019			2018			2017
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	326,747		$	344,616		$	394,427
Natural gas, NGLs and condensate sales		86,994			134,834			68,459
Other revenues		29,787			27,203			25,855
Total revenues		443,528			506,653			488,741
Costs and expenses:
Cost of natural gas and NGLs		63,438			107,661			57,237
Operation and maintenance		98,719			100,978			93,882
General and administrative		55,947			54,991			56,351
Depreciation and amortization		110,354			107,263			115,737
Transaction costs		3,017			—			50
(Gain) loss on asset sales, net		(1,536	)		—			527
Long-lived asset impairment		60,507			7,186			188,702
Goodwill impairment		16,211			—			—
Total costs and expenses		406,657			378,079			512,486
Other income (expense)		451			(169	)		298
Interest expense		(91,966	)		(82,830	)		(88,701	)
Early extinguishment of debt		—			—			(22,039	)
(Loss) income before income taxes and loss from equity method investees		(54,644	)		45,575			(134,187	)
Income tax expense		(1,231	)		(367	)		(504	)
Loss from equity method investees		(337,851	)		(10,888	)		(2,223	)
Net (loss) income	$	(393,726	)	$	34,320		$	(136,914	)
Less:
Net (loss) income attributable to noncontrolling interest		(209,275	)		2,774			46,497
Net (loss) income attributable to limited partners		(184,451	)		31,546			(183,411	)
Net income attributable to Series A Preferred Units		28,500			28,500			3,563
Net income attributable to Subsidiary Series A Preferred Units		58			—			—
Net (loss) income attributable to common limited partners	$	(213,009	)	$	3,046		$	(186,974	)
(Loss) income per limited partner unit:
Common unit – basic	$	(4.70	)	$	0.07		$	(4.13	)
Common unit – diluted	$	(4.70	)	$	0.07		$	(4.13	)
Weighted-average limited partner units outstanding:
Common units – basic		45,319			45,319			45,319
Common units – diluted		45,319			45,630			45,319

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

EX 99.3-5

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	Noncontrolling Interest
	Series A Preferred Units			Common Noncontrolling Interests (1)			Partners’ Capital			Total
	(In thousands)
Partners’ capital, January 1, 2017	$	—		$	629,488		$	1,005,932		$	1,635,420
Net income (loss)		3,563			46,497			(186,974	)		(136,914	)
Unit-based compensation		—			7,878			—			7,878
Effect of common unit issuances under SMLP LTIP		—			1,209			(1,209	)		—
Tax withholdings on vested SMLP LTIP awards		—			(2,236	)		—			(2,236	)
Net cash distributions to SMLP unitholders		(2,375	)		(107,598	)		—			(109,973	)
Net cash distributions to Energy Capital Partners		—			—			(301,672	)		(301,672	)
Issuance of Series A Preferred Units, net of offering costs		293,238			—			—			293,238
ATM Program issuances, net of costs		—			14,551			2,527			17,078
Secondary offering of SMLP common units		—			60,981			33,659			94,640
Other		—			(199	)		—			(199	)
Partners’ capital, December 31, 2017, as reported	$	294,426		$	650,571		$	552,263		$	1,497,260
January 1, 2018 impact of Topic 606 day 1 adoption		—			2,669			1,545			4,214
Partners’ capital, January 1, 2018		294,426			653,240			553,808			1,501,474
Net income		28,500			2,774			3,046			34,320
Net cash distributions to SMLP unitholders		(28,500	)		(109,101	)		—			(137,601	)
Net cash distributions to Energy Capital Partners		—			—			(11,800	)		(11,800	)
Unit-based compensation		—			8,088			—			8,088
Effect of common unit issuances under SMLP LTIP		—			1,575			(1,575	)		—
Tax withholdings on vested SMLP LTIP awards		—			(1,974	)		—			(1,974	)
Other		(810	)		(130	)		—			(940	)
Partners’ capital, December 31, 2018	$	293,616		$	554,472		$	543,479		$	1,391,567
Net income (loss)		28,500			(209,275	)		(213,009	)		(393,784	)
Net cash distributions to noncontrolling interest SMLP unitholders		(28,500	)		(68,874	)		—			(97,374	)
Net cash distributions to Energy Capital Partners		—			—			(120,730	)		(120,730	)
Unit-based compensation		—			8,171			—			8,171
Effect of common unit issuances under SMLP LTIP		—			2,664			(2,664	)		—
Tax withholdings on vested SMLP LTIP awards		—			(2,614	)		—			(2,614	)
Conversion of noncontrolling interest related to cancelation of subsidiary incentive distribution rights		—			(48,203	)		48,203			—
Conversion of noncontrolling interest related to partial cancellation of subsidiary of DPPO		—			(50,271	)		50,271			—
Partners’ capital, December 31, 2019	$	293,616		$	186,070		$	305,550		$	785,236

(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.

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

EX 99.3-6

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2019				2018			2017
	(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(393,726	)		$	34,320		$	(136,914	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization		111,574				106,930			115,134
Noncash lease expense		3,086				—			—
Amortization of debt issuance costs		6,313				6,142			5,445
Unit-based and noncash compensation		8,171				8,328			7,951
Loss from equity method investees		337,851				10,888			2,223
Distributions from equity method investees		37,300				35,271			40,220
(Gain) loss on asset sales, net		(1,536	)			—			527
Long-lived asset impairment		60,507				7,186			188,702
Goodwill impairment		16,211				—			—
Early extinguishment of debt		—				—			22,039
Write-off of debt issuance costs		—				—			302
Changes in operating assets and liabilities:
Accounts receivable		(5,466	)			(25,635	)		25,063
Trade accounts payable		(96	)			85			(3,256	)
Accrued expenses		(10,572	)			13,903			1,227
Deferred revenue, net		1,683				5,355			(40,758	)
Ad valorem taxes payable		(1,525	)			2,211			(2,248	)
Accrued interest		7				(140	)		(7,736	)
Accrued environmental remediation, net		(1,152	)			292			(4,109	)
Other, net		(6,889	)			1,094			(764	)
Net cash provided by operating activities		161,741				206,230			213,048
Cash flows from investing activities:
Capital expenditures		(182,291	)	��		(200,586	)		(124,215	)
Proceeds from asset sale (net of cash of $1,475 for the year ended December 31, 2019)		102,111				496			2,300
Contributions to equity method investees		—				(4,924	)		(25,513	)
Distributions from equity method investment		7,313				—			—
Investment in equity method investee		(18,316	)			—			—
Other, net		313				(284	)		(458	)
Net cash used in investing activities		(90,870	)			(205,298	)		(147,886	)

EX 99.3-7

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Cash flows from financing activities:
Distributions to noncontrolling interest SMLP unitholders		(68,874	)		(109,101	)		(107,598	)
Distributions to Series A Preferred unitholders		(28,500	)		(28,500	)		(2,375	)
Distributions to mandatorily redeemable Class C unitholders		—			—			(99,323	)
Distributions to Energy Capital Partners		(120,730	)		(11,800	)		(301,672	)
Borrowings under Revolving Credit Facility		369,000			289,000			247,500
Repayments under Revolving Credit Facility		(158,000	)		(84,000	)		(634,500	)
Borrowings under SMP Holdings Term Loan B		—			—			300,000
Repayments under SMP Holdings Term Loan B		(65,250	)		(49,250	)		(24,000	)
Debt issuance costs		(673	)		(518	)		(25,061	)
Payment of redemption and call premiums on senior notes		—			—			(17,932	)
Proceeds from ATM Program common unit issuances, net of costs		—			—			17,078
Proceeds from secondary offering common units, net of costs		—			—			94,640
Proceeds from issuance of Series A preferred units, net of costs		27,392			—			293,238
Issuance of senior notes		—			—			500,000
Tender and redemption of senior notes		—			—			(300,000	)
Other, net		(4,487	)		(4,186	)		(3,124	)
Net cash (used in) provided by financing activities		(50,122	)		1,645			(63,129	)
Net change in cash, cash equivalents and restricted cash		20,749			2,577			2,033
Cash, cash equivalents and restricted cash, beginning of period		16,173			13,596			11,563
Cash, cash equivalents and restricted cash, end of period (1)	$	36,922		$	16,173		$	13,596
Supplemental cash flow disclosures:
Cash interest paid	$	92,536		$	85,233		$	88,193
Less capitalized interest		6,974			8,497			2,579
Interest paid (net of capitalized interest)	$	85,562		$	76,736		$	85,614
Cash paid for taxes	$	150		$	175		$	—
Noncash investing and financing activities
Capital expenditures in trade accounts payable (period-end accruals)	$	19,846		$	33,750		$	11,792
Asset contribution to an equity method investment		23,643			—			—
Capital expenditures relating to contributions in aid of construction for Topic 606 day 1 adoption		—			33,123			—
Right-of-use assets relating to Topic 842		5,448			—			—

(1) A reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets follow:

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Cash and cash equivalents	$	9,530	$	16,173	$	13,596
Restricted cash		27,392		—		—
Total cash, cash equivalents and restricted cash	$	36,922	$	16,173	$	13,596

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

EX 99.3-8

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization.

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

As described further in Note 19, the Partnership closed on its Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company (“ECP”) on May 28, 2020 to acquire all the outstanding limited liability company interests of Summit Midstream Partners, LLC a Delaware limited liability company (“Summit Investments”). We refer to the transactions contemplated by the Purchase Agreement as the (“GP

Buy-In

Transaction”). As a result of the GP

Buy-In

Transaction, the Partnership now indirectly owns its own general partner, Summit Midstream Partners GP, LLC (the “General Partner”), an entity controlled by Summit Investments.

Under GAAP, the GP

Buy-In

Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein prior to the GP

Buy-In

Transaction are those of Summit Investments. Prior to the GP

Buy-In

Transaction, Summit Investments controlled SMLP and SMLP’s financial statements were consolidated into Summit Investments.

Business Operations.

We provide natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term,

fee-based

agreements with our customers. Our results are primarily driven by the volumes of natural gas that we gather, compress, treat and/or process as well as by the volumes of crude oil and produced water that we gather. We are the owner-operator of, or have significant ownership interests in, the following gathering and transportation systems:

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

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

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

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

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

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

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

EX 99.3-9

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

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

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

Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 17 for details on the sale of Tioga Midstream.

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

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

Presentation and Consolidation.

We prepare our consolidated financial statements in accordance with GAAP as established by the FASB. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the disclosure of commitments and contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash, Cash Equivalents and Restricted Cash.

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash that is held by a major bank and has restrictions on its availability to us is classified as restricted cash. See Note 12 for additional information.

Accounts Receivable.

Accounts receivable relate to gathering and other services provided to our customers and other counterparties. We evaluate the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent we doubt the collectability of a specific customer or counterparty receivable, we recognize an allowance for doubtful accounts. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.

Property, Plant and Equipment.

We record property, plant and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress.

We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow.

	Useful lives (In years)
Gathering and processing systems and related equipment		12-30
Other		4-15

EX 99.3-10

Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated.

We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any.

Accrued capital expenditures are reflected in trade accounts payable.

Asset Retirement Obligations.

We record a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, we then evaluate whether the expected date and related costs of retirement can be estimated. We have concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because we did not have sufficient information to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of any significant assets, we did not provide for any asset retirement obligations as of December 31, 2019 or 2018.

Amortizing Intangibles.

Upon the acquisition of DFW Midstream, certain of its gas gathering contracts were deemed to have above-market pricing structures. We have recognized the above-market contracts as favorable gas gathering contracts. We amortize the favorable contracts using a straight-line method over the contract’s estimated useful life. We define useful life as the period over which the contract is expected to contribute to our future cash flows. These contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these contracts in Other revenues.

We amortize all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 3 years to 25 years. We recognize the amortization expense associated with these contracts in Depreciation and amortization expense.

We have

rights-of-way

associated with city easements and easements granted within existing

rights-of-way.

We amortize these intangible assets over the shorter of the contractual term of the

rights-of-way

or the estimated useful life of the gathering system. The contractual terms of the

rights-of-way

range from 20 years to 30 years. We recognize the amortization expense associated with

rights-of-way

assets in Depreciation and amortization expense.

Goodwill.

Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30. 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. As of December 31, 2019, we did not have a goodwill balance on our consolidated balance sheet.

Equity Method Investments.

We account for investments in which we exercise significant influence using the equity method so long as we (i) do not control the investee and (ii) are not the primary beneficiary. We recognize these investments in investment in equity method investees in the accompanying consolidated balance sheets. We recognized (i) our proportionate share of earnings or loss in net income for Ohio Gathering, on a

one-month

lag, and (ii) an other-than-temporary impairment for Ohio Gathering, based on the financial information available to us during the reporting period.

We recognize an other-than-temporary impairment for losses in the value of equity method investees when evidence indicates that the carrying amount is no longer supportable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. We evaluate our equity method investments whenever a triggering event exists that would indicate a need to assess the investment for potential impairment.

EX 99.3-11

Other Noncurrent Assets.

Other noncurrent assets primarily consist of external costs incurred in connection with the closing of our Revolving Credit Facility and related amendments. We capitalize and then amortize these debt issuance costs on a straight-line basis, which approximates the effect of the effective interest rate method, over the life of the respective debt instrument. We recognize the amortization of the Revolving Credit Facility debt issuance costs in interest expense.

Debt Issuance Costs.

Debt issuance costs, other than those associated with our Revolving Credit Facility, are reflected in the carrying value of the Senior Notes and Term Loan B as an adjustment to the principal amount and amortized on a straight-line basis, which approximates the effect of the effective interest rate method, over the life of the respective debt instrument. We recognize the amortization of the Senior Notes and Term Loan B debt issuance costs in interest expense.

Impairment of Long-Lived Assets.

We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If we conclude that an asset’s carrying value will not be recovered through future cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. We determine fair value using either a market-based approach, an income-based approach or a combination of the two approaches.

Derivative Contracts.

We have commodity price exposure related to our sale of the physical natural gas we retain from certain DFW Midstream customers and our procurement of electricity to operate the DFW Midstream system’s electric-drive compression assets. Our gas gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we gather to offset the power costs we incur to operate these electric-drive compression assets. We manage this direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices based on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for

mark-to-market

recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. We have designated these contracts as normal under the normal purchase and sale exception under the accounting standards for derivatives. We do not enter into risk management contracts for speculative purposes.

Restructuring Costs.

Our restructuring costs are comprised primarily of employee termination costs related to headcount reductions. A liability for costs associated with an exit or disposal activity is recognized and measured initially at fair value only when the liability is incurred. Our restructuring charges also include relocation expenses and advisory costs. We reassess the liability periodically based on market conditions. Refer to Note 17 for additional details.

Fair Value of Financial Instruments.

The fair-value-measurement standard under GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which the inputs are observable. The three levels of the fair value hierarchy are as follows:

• Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities;

• Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and

EX 99.3-12

• Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an internally developed present value of future cash flows model that underlies management’s fair value measurement).

Commitments and Contingencies.

We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. We recognize gain contingencies when their realization is assured beyond a reasonable doubt.

Revenue Recognition.

The majority of our revenue is derived from long-term,

fee-based

contracts with original terms of up to 25 years. We account for revenue in accordance with Topic 606, which we adopted on January 1, 2018, using the modified retrospective method.

We recognize revenue earned from

fee-based

gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain

percent-of-proceeds

arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues.

We provide gathering and/or processing services principally under contracts that contain one or more of the following arrangements:

• Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, compressing and/or processing and (ii) crude oil and/or produced water gathering.

• Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs.

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

We recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. In making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.

EX 99.3-13

Unit-Based Compensation.

For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense in the statements of operations over the vesting period of the respective awards.

Income Taxes.

As a partnership, we are generally not subject to federal and state income taxes, except as noted below. However, our unitholders are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements under our Partnership Agreement. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership.

In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the “Texas Margin Tax”). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. Our financial statements reflect provisions for these tax obligations.

Earnings or Loss Per Unit.

We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our Partnership Agreement, to common limited partners under the

two-class

method, after deducting (i) any payment of IDRs, by the weighted-average number of limited partner units outstanding (for periods presented through the Equity Restructuring), (ii) the General Partner’s approximate 2% interest in net income or loss (for periods presented up through the Equity Restructuring), and (iii) net income attributable to Series A Preferred Units and Subsidiary Series A Preferred Units. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.

Environmental Matters.

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their realization is assured beyond a reasonable doubt.

Recent Accounting Pronouncements.

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

Recently Adopted Accounting Pronouncements

. We have recently adopted the following accounting pronouncement:

• ASU No. 2016-02 Leases (“Topic 842”). We adopted Topic 842 with a date of initial application of January 1, 2019. We applied Topic 842 by recognizing (i) a $5.4 million right-of-use (“ROU”) asset which represents the right to use, or to control the use of, specified assets for a lease term. The ROU asset is included in the Property, plant and equipment, net caption on the consolidated balance sheet; and (ii) a $5.4 million lease liability for the obligation to make lease payments arising from the leases. The lease liability is included in the Other current liabilities and Other noncurrent liabilities captions on the consolidated balance sheet. The comparative information has not been adjusted and is reported under the accounting standards in effect for those periods. Refer to Note 16 for additional information.

EX 99.3-14

Accounting Pronouncements Pending Adoption

. We have not yet adopted the following accounting pronouncements as of December 31, 2019:

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

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

3. REVENUE

The majority of our revenue is derived from long-term,

fee-based

contracts with our customers, which include original terms of up to 25 years. We recognize revenue earned from

fee-based

gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain

percent-of-proceeds

arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in Natural gas, NGLs and condensate sales; the associated expense is included in Operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues.

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

in-kind,

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

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

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

Performance obligations

. The majority of our contracts have a single performance obligation which is either to provide gathering services (an integrated service) or sell natural gas, NGLs and condensate, which are both satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. We also have certain contracts with multiple performance obligations. They include an option for the customer to acquire additional

EX 99.3-15

services such as contracts containing MVCs. These performance obligations would also be satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. In these instances, we allocate the contract’s transaction price to each performance obligation using our best estimate of the standalone selling price of each service in the contract.

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

non-guaranteed,

as-available

service contracts.

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

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

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

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

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

We applied the practical expedient in paragraph

606-10-50-14

of Topic 606 for certain arrangements that we consider optional purchases (i.e., there is no enforceable obligation for the customer to make purchases) and those amounts are therefore excluded from the table.

	2020		2021		2022		2023		2024		Thereafter
	(In thousands)
Gathering services and related fees	$	122,055	$	102,127	$	84,736	$	66,693	$	50,608	$	59,602

Revenue by Category

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

	Reportable Segments
	Year ended December 31, 2019
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	31,926	$	77,626	$	21,940	$	3,610	$	121,357	$	47,862	$	24,471	$	328,792	$	(2,045	)	$	326,747
Natural gas, NGLs and condensate sales		—		16,461		389		16,383		7,954		17,147		—		58,334		28,660			86,994
Other revenues		2,065		11,564		3,721		310		4,327		6,793		—		28,780		1,007			29,787
Total	$	33,991	$	105,651	$	26,050	$	20,303	$	133,638	$	71,802	$	24,471	$	415,906	$	27,622		$	443,528

EX 99.3-16

	Reportable Segments
	Year ended December 31, 2018
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	35,233	$	79,606	$	11,251	$	115	$	135,810	$	59,030	$	29,573	$	350,618	$	(6,002	)	$	344,616
Natural gas, NGLs and condensate sales		—		31,840		371		843		14,800		2,523		—		50,377		84,457			134,834
Other revenues		—		12,204		3,672		—		4,909		6,712		—		27,497		(294	)		27,203
Total	$	35,233	$	123,650	$	15,294	$	958	$	155,519	$	68,265	$	29,573	$	428,492	$	78,161		$	506,653

Contract balances

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

	December 31, 2019			December 31, 2018
	(In thousands)
Contract assets, beginning of period	$	8,755		$	—
Additions		18,077			26,403
Transfers out		(22,930	)		(17,648	)
Contract assets, end of period	$	3,902		$	8,755

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

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

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. We recognize contract liabilities under these arrangements in revenue over the contract period. For the years ended December 31, 2019 and 2018, we recognized $10.1 million and $10.8 million, respectively, of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. See Note 9 for additional details.

4. SEGMENT INFORMATION

As of December 31, 2019, our reportable segments are:

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

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

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

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

• the Permian Basin, which is served by Summit Permian;

• the Piceance Basin, which is served by Grand River;

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

• the Marcellus Shale, which is served by Mountaineer Midstream.

Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Until December 1, 2019, we owned certain assets in the Red Rock Gathering system operating in the Piceance Basin. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream and on the sale of certain assets in the Red Rock Gathering system.

EX 99.3-17

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

The Ohio Gathering reportable segment includes our investment in Ohio Gathering. Income or loss from equity method investees, as reflected on the statements of operations, relates to Ohio Gathering and is recognized and disclosed on a

one-month

lag (see Note 8).

For the year ended December 31, 2019, other than the investment activity described in Note 8, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the third quarter of 2021.

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

Assets by reportable segment follow.

	December 31,
	2019		2018			2017
	(In thousands)
Assets (1):
Utica Shale	$	206,368	$	207,357		$	212,311
Ohio Gathering		275,000		649,250			690,485
Williston Basin		452,152		526,819			512,860
DJ Basin		205,308		166,580			79,438
Permian Basin		185,708		145,702			57,590
Piceance Basin		631,140		699,638			719,284
Barnett Shale		350,638		376,564			383,306
Marcellus Shale		184,631		208,790			217,362
Total reportable segment assets		2,490,945		2,980,700			2,872,636
Corporate and Other		83,153		56,838			35,332
Eliminations		—		(4,319	)		(249	)
Total assets	$	2,574,098	$	3,033,219		$	2,907,719

(1) At December 31, 2019, Corporate and Other included $34.7 million relating to our investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet). At December 31, 2018, Corporate and Other included $9.6 million of capital expenditures relating to the Double E Project.

Revenues by reportable segment follow.

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Revenues (1):
Utica Shale	$	33,991		$	35,233		$	38,907
Williston Basin		105,651			123,650			161,503
DJ Basin		26,050			15,294			11,860
Permian Basin		20,303			958			—
Piceance Basin		133,638			155,519			154,893
Barnett Shale		71,802			68,265			71,667
Marcellus Shale		24,471			29,573			30,394
Total reportable segments revenue		415,906			428,492			469,224
Corporate and Other		30,552			88,286			26,446
Eliminations		(2,930	)		(10,125	)		(6,929	)
Total revenues	$	443,528		$	506,653		$	488,741

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

EX 99.3-18

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

	Year ended December 31,
	2019			2018			2017
Percentage of total revenues (1):
Counterparty A - Piceance Basin		11	%		*			*
Counterparty B - Williston Basin		10	%		*			13	%
Counterparty C - Piceance Shale		*			10	%		*

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

* Less than 10%

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

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Depreciation and amortization (1):
Utica Shale	$	7,659	$	7,672	$	7,009
Williston Basin		19,829		22,642		33,772
DJ Basin		3,732		3,133		2,636
Permian Basin		4,868		243		—
Piceance Basin		47,018		46,919		46,289
Barnett Shale (2)		16,575		15,325		15,001
Marcellus Shale		9,141		9,090		9,047
Total reportable segment depreciation and amortization		108,822		105,024		113,754
Corporate and Other		2,752		1,906		1,364
Total depreciation and amortization	$	111,574	$	106,930	$	115,118

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

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

Cash paid for capital expenditures by reportable segment follow.

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Cash paid for capital expenditures (1):
Utica Shale	$	3,902	$	5,719	$	22,921
Williston Basin		30,861		25,202		17,309
DJ Basin		80,487		64,920		7,150
Permian Basin		44,955		83,823		56,020
Piceance Basin		1,946		7,887		16,564
Barnett Shale (2)		184		1,370		569
Marcellus Shale		693		1,030		641
Total reportable segment capital expenditures		163,028		189,951		121,174
Corporate and Other		19,263		10,635		3,041
Total cash paid for capital expenditures	$	182,291	$	200,586	$	124,215

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

(2) For the year ended December 31, 2019, the amount includes sales tax reimbursements of $1.1 million.

For the years ended December 31, 2019 and 2018, Corporate and Other includes cash paid of $1.6 million and $3.3 million, respectively, for corporate purposes; the remainder represents capital expenditures relating to the Double E Project.

We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) impairments (viii) other noncash expenses or losses, less other noncash income or gains and (ix)

EX 99.3-19

restructuring expenses. We define proportional adjusted EBITDA for our equity method investees as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items, and amortization for deferred contract costs; and (ii) our ownership interest in Ohio Gathering during the respective period.

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

Segment adjusted EBITDA by reportable segment follows.

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	29,292		$	30,285		$	34,011
Ohio Gathering		39,126			39,969			41,246
Williston Basin		69,437			76,701			66,413
DJ Basin		18,668			7,558			6,624
Permian Basin		(879	)		(1,200	)		—
Piceance Basin		98,765			111,042			111,113
Barnett Shale		43,043			43,268			46,232
Marcellus Shale		20,051			24,267			23,888
Total of reportable segments’ measures of profit	$	317,503		$	331,890		$	329,527

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

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Reconciliation of (loss) income before income taxes and loss from equity method investees to total of reportable segments’ measures of profit:
(Loss) income before income taxes and loss from equity method investees	$	(54,644	)	$	45,575		$	(134,187	)
Add:
Corporate and Other expense		44,808			45,131			40,803
Interest expense		91,966			82,830			88,701
Early extinguishment of debt		—			—			22,039
Depreciation and amortization		111,574			106,930			115,118
Proportional adjusted EBITDA for equity method investees		39,126			39,969			41,246
Adjustments related to MVC shortfall payments		3,476			(3,632	)		(41,373	)
Adjustments related to capital reimbursement activity		(2,156	)		(427	)		—
Unit-based and noncash compensation		8,171			8,328			7,951
(Gain) loss on asset sales, net		(1,536	)		—			527
Long-lived asset impairment		60,507			7,186			188,702
Goodwill impairment		16,211			—			—
Total of reportable segments’ measures of profit	$	317,503		$	331,890		$	329,527

For the years ended December 31, 2019 and 2018, adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC (see Note 3).

Contributions in aid of construction are recognized over the remaining term of the respective contract. We include adjustments related to capital reimbursement activity in our calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction.

EX 99.3-20

For the year ended December 31, 2017, we included adjustments related to MVC shortfall payments in our calculation of segment adjusted EBITDA to account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. With respect to the impact of a net change in deferred revenue for MVC shortfall payments, we treated increases in deferred revenue balances as a favorable adjustment to segment adjusted EBITDA, while decreases in deferred revenue balances were treated as an unfavorable adjustment to segment adjusted EBITDA. We also included a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment.

Adjustments related to MVC shortfall payments by reportable segment follow.

	Year ended December 31, 2019
	Williston Basin		Piceance Basin			Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	—	$	(103	)	$	3,579	$	3,476

	Year ended December 31, 2018
	Williston  Basin		Piceance Basin		Barnett Shale			Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	—	$	10	$	(3,642	)	$	(3,632	)

	Year Ended December 31, 2017
	Williston Basin			Piceance Basin			Barnett Shale			Total
	(In thousands)
Adjustments related to MVC shortfall payments:
Net change in deferred revenue for MVC shortfall payments	$	(37,693	)	$	(3,065	)	$	—		$	(40,758	)
Expected MVC shortfall adjustments		—			(3	)		(612	)		(615	)
Total adjustments related to MVC shortfall payments	$	(37,693	)	$	(3,068	)	$	(612	)	$	(41,373	)

5. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	December 31, 2019		December 31, 2018
	(In thousands)
Gathering and processing systems and related equipment	$	2,182,950	$	2,155,325
Construction in progress		78,716		137,920
Land and line fill		10,137		11,748
Other		54,595		47,319
Total		2,326,398		2,352,312
Less accumulated depreciation		443,909		388,213
Property, plant and equipment, net	$	1,882,489	$	1,964,099

During 2019, 2018 and 2017, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired. As such, we reviewed the assets that had been identified as potentially impaired and estimated the fair value of the identified property, plant and equipment using a market-based approach.

In December 2019, we sold certain Red Rock Gathering system assets for a cash purchase price of $12.0 million. Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. See Note 17 for additional details.

EX 99.3-21

In December 2019, in connection with the cancellation of a project, we determined certain processing plant assets in the Permian Basin would no longer be utilized. As a result, we recorded an impairment charge of $0.7 million related to these assets in the fourth quarter of 2019. See Note 6 for additional details.

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

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

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

In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $3.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. In addition, we reviewed the other assets that had been identified as potentially impaired and recognized the long-lived asset impairments in the table below.

In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain long-lived assets related to the Bison Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $101.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. See Note 6 for additional details.

During 2019, 2018 and 2017, we recognized the following long-lived asset impairments, by segment.

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Long-lived asset impairment:
Williston Basin	$	10	$	3,972	$	101,961
Piceance Basin		14,162		1,004		697
DJ Basin		34,913		9		—
Barnett Shale		9,629		—		—
Utica Shale		—		1,440		878
Permian Basin		726		761		—

Our impairment determinations, in the context of these reviews, involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as

non-recurring

Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

Depreciation expense and capitalized interest follow.

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Depreciation expense	$	78,489	$	74,674	$	75,382
Capitalized interest		6,974		8,497		2,579

EX 99.3-22

6. AMORTIZING INTANGIBLE ASSETS

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

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

	December 31, 2018
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(13,905	)	$	10,290
Contract intangibles		278,448		(143,962	)		134,486
Rights-of-way		166,209		(37,569	)		128,640
Total intangible assets	$	468,852	$	(195,436	)	$	273,416

In December 2019, in connection with the cancellation of a project, we determined certain

rights-of-way

intangible assets in the Permian Basin would no longer be utilized (see Note 5). As a result, we recorded an impairment charge of $0.6 million in the fourth quarter of 2019.

Also in early 2019, certain events occurred which indicated that certain long-lived assets relating to the Barnett Shale reporting segment could be impaired (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of

rights-of-way

intangible assets. We concluded the

rights-of-way

intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019.

In December 2017, in connection with certain strategic initiatives, we evaluated certain long-lived assets relating to the Bison Midstream system within the Williston Basin reporting segment (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of contract intangible assets and

rights-of-way

intangible assets. We concluded the contract intangible assets were also impaired and, as a result, we recorded an impairment charge of $85.2 million.

We recognized amortization expense in Other revenues as follows:

	Year ended December 31,
	2019			2018			2017
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(1,220	)	$	(1,555	)	$	(1,555	)

We recognized amortization expense in costs and expenses as follows:

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Amortization expense – contract intangibles	$	25,587	$	26,141	$	34,202
Amortization expense – rights-of-way		6,278		6,448		6,153

EX 99.3-23

The estimated aggregate annual amortization expected to be recognized for as of December 31, 2019 for each of the five succeeding fiscal years follows.

	Intangible assets
	(In thousands)
2020	$	31,901
2021		28,209
2022		25,142
2023		25,088
2024		14,917

7. GOODWILL

Goodwill for the year ended December 31, 2018 of $16.2 million was related to the acquisition of the Mountaineer Midstream system in 2013.

Accumulated goodwill impairments by reportable segment for those reporting units that have previously recognized goodwill follow.

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Accumulated goodwill impairment:
Piceance Basin	$	45,478	$	45,478	$	45,478
Williston Basin		257,572		257,572		257,572
Marcellus Shale		16,211		—		—
Total accumulated goodwill impairment	$	319,261	$	303,050	$	303,050

We evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. If the reporting unit’s fair value exceeds its carrying value, including goodwill, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value, including goodwill, exceeds its fair value, we recognize the excess of the carrying value over the fair value as a goodwill impairment loss.

We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2019 using a combination of the income and market approaches. We determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, we recognized a goodwill impairment charge of $16.2 million for the year ended December 31, 2019.

We had no impairments of goodwill for the years ended December 31, 2018 and 2017.

Fair Value Measurement.

Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the valuations. As such, the fair value measurements utilized within these models are classified as

non-recurring

Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.

8. EQUITY METHOD INVESTMENTS

Double E

In June 2019, we formed Double E in connection with the Double E Project. Effective June 26, 2019, Summit Permian Transmission, a wholly owned and consolidated subsidiary of the Partnership, and our JV Partner executed the Agreement whereby Double E will provide natural gas transportation services from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. Concurrent with the Agreement, we issued a parental guaranty to fund any capital calls not satisfied by Summit Permian Transmission during the construction of Double E, for an amount not to exceed $350.0 million. At December 31, 2019, our outstanding parental guaranty for Double E was $308.9 million. In connection with the Agreement and the related Double E Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and our JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Agreement, Double E distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, we also made additional cash investments of $18.3 million through December 2019.

EX 99.3-24

Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Agreement, Summit Permian Transmission was not deemed to be the primary beneficiary due to the JV Partner’s voting rights on significant matters. We account for our ownership interest in Double E as an equity method investment because we have significant influence over Double E. Our portion of Double E’s net assets, which was $34.7 million at December 31, 2019, is reported under the caption Investment in equity method investees on the consolidated balance sheet.

For the year ended December 31, 2019, other than the investment activity noted above, Double E did not have any results of operations given that the Double E Project is currently under development.

Ohio Gathering

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

fee-based

gathering agreements, which include acreage dedications.

Our initial investment in Ohio Gathering in 2014 included a $190.0 million payment to acquire a 1% interest from a third party, which included an option to increase our ownership to 40%, as well as a series of contributions directly to Ohio Gathering in 2014, which increased our ownership to 40%. Concurrent with and subsequent to the exercise of the option, the

non-affiliated

owners have retained their respective 60% ownership interest in Ohio Gathering (the

“Non-affiliated

Owners”).

We account for our ownership interests in Ohio Gathering as an equity method investment because we have joint control with the

Non-affiliated

Owners, which gives us significant influence.

We recognized the $190.0 million paid for the initial 1% interest as an investment in Ohio Gathering at inception. In addition, Ohio Gathering assigned a value of $7.5 million to the exercise option, which it ultimately attributed to our capital account. Neither of the aforementioned transactions involved a flow of funds to or from Ohio Gathering. As such, they created a basis difference between our recorded investment in equity method investees and the amount attributed to us by Ohio Gathering within its financial statements.

In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. In accordance with ASC Topic 323, we completed an equity method impairment analysis to determine the equity method impairment charge to be recorded on our consolidated financial statements resulting from an other-than-temporary impairment. As a result of our analysis, an impairment charge of approximately $329.7 million was recorded in 2019 in Loss from equity method investments on the accompanying consolidated statements of operations.

The fair value of our investment in Ohio Gathering was determined based upon applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability weighted average set of cash flow forecasts and a discount rate of approximately 9.0 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the Ohio Gathering equity method investment represents a Level 3 measurement. As a result, actual results may differ from the estimates and assumptions made for purposes of this impairment analysis.

Also in December 2019, an impairment loss of long-lived assets was recognized by OCC. Although we recognize activity for Ohio Gathering on a

one-month

lag, we recorded an impairment loss of $6.3 million in Loss from equity method investees in the consolidated statements of operations because the information was available to us.

In December 2018, Ohio Gathering was involved in legal proceedings relating to a dispute regarding pipeline right of way rights and associated trespass claims that took place prior to December 31, 2018. Ohio Gathering received a judgment on those proceedings in January 2019 and recorded an estimate of the legal exposure as of December 31, 2018. Although

EX 99.3-25

we recognize activity for Ohio Gathering on a

one-month

lag, we recorded the asset impairments and legal contingency in our results of operations for the year ending December 31, 2018 because the information was available to us. We recorded our then 40% share of the asset impairments and legal contingency amounting to $7.7 million in 2018 in Loss from equity method investees in the consolidated statements of operations.

As a result of our joint venture partner funding a disproportionate amount of the capital calls during the year ended December 31, 2019, our ownership interest in Ohio Gathering decreased from 40.0% at December 31, 2018, to 38.5% at December 31, 2019.

A reconciliation of our 38.5% and 40% ownership interest in Ohio Gathering to our investment per Ohio Gathering’s books and records follows for the years ending December 31, 2019 and 2018, respectively (in thousands).

	2019		2018
	(In thousands)
Investment in Ohio Gathering, December 31	$	275,000	$	649,250
December cash distributions		2,700		2,736
Impairment loss (1)		232,521		5,652
Loss contingency		—		2,040
Basis difference		—		(116,832	)
Investment in Ohio Gathering, net of basis difference, November 30	$	510,221	$	542,846

(1) Amount is comprised of (i) a $329.7 million impairment of our equity method investment in Ohio Gathering; (ii) the write-off of our basis difference of ($103.5) million in Ohio Gathering as a result of the impairment in our equity method investment in Ohio Gathering; and (iii) a $6.3 million impairment of long-lived assets in OCC.

Summarized balance sheet information for OGC and OCC follows (amounts represent 100% of investee financial information).

	November 30, 2019				November 30, 2018
	OGC		OCC		OGC		OCC
	(In thousands)
Current assets	$	41,972	$	2,187	$	37,403	$	3,716
Noncurrent assets		1,281,171		28,323		1,262,253		27,203
Total assets	$	1,323,143	$	30,510	$	1,299,656	$	30,919
Current liabilities	$	21,798	$	4,016	$	19,903	$	3,912
Noncurrent liabilities		4,113		6,683		3,688		8,807
Total liabilities	$	25,911	$	10,699	$	23,591	$	12,719

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

	Twelve months ended November 30, 2019					Twelve months ended November 30, 2018				Twelve months ended November 30, 2017
	OGC		OCC			OGC		OCC		OGC		OCC
	(In thousands)
Total revenues	$	142,138	$	8,601		$	142,398	$	10,177	$	140,679	$	8,607
Total operating expenses		108,234		38,815			136,722		9,053		111,897		8,298
Net income (loss)		33,897		(30,214	)		5,670		498		28,785		(907	)

9. DEFERRED REVENUE

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

EX 99.3-26

Many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our MVCs to the extent that a customer’s actual throughput volumes are above or below its MVC for the applicable contracted measurement period. These provisions include the following:

• To the extent that a customer’s throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of that customer’s MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable).

• To the extent that a customer’s throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply will be less than the weighted-average of the original stated contract terms of our MVCs.

• To the extent that certain of our customers’ throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.

A rollforward of current deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2018	$	18	$	1,017	$	358	$	7,038	$	1,619	$	38	$	10,088
Additions		18		1,744		943		21,955		1,651		96		26,407
Less revenue recognized		18		1,347		562		21,377		1,628		96		25,028
Current deferred revenue, December 31, 2018		18		1,414		739		7,616		1,642		38		11,467
Additions		18		2,262		5,165		16,211		1,632		38		25,326
Less revenue recognized		18		1,743		3,044		16,813		1,644		38		23,300
Current deferred revenue, December 31, 2019	$	18	$	1,933	$	2,860	$	7,014	$	1,630	$	38	$	13,493

A rollforward of noncurrent deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total noncurrent
	(In thousands)
Noncurrent deferred, revenue, January 1, 2018	$	39	$	4,215	$	4,505	$	18,219	$	8,217	$	333	$	35,528
Additions		—		1,851		3,720		7,869		3,062		—		16,502
Less reclassification to current deferred revenue		18		1,673		941		8,146		1,651		97		12,526
Noncurrent deferred revenue, December 31, 2018		21		4,393		7,284		17,942		9,628		236		39,504
Additions		—		1,940		5,470		6,104		1,579		—		15,093
Less reclassification to current deferred revenue		18		2,699		5,165		6,336		1,632		38		15,888
Noncurrent deferred revenue, December 31, 2019	$	3	$	3,634	$	7,589	$	17,710	$	9,575	$	198	$	38,709

EX 99.3-27

10. DEBT

Debt consisted of the following:

	December 31, 2019			December 31, 2018
	(In thousands)
Summit Holdings’ variable rate senior secured Revolving Credit Facility  ( 4.55% at December 31, 2019 and 5.03% at December 31, 2018) due May 2022	$	677,000		$	466,000
Summit Holdings’ 5.5% senior unsecured notes due August 2022		300,000			300,000
Less unamortized debt issuance costs (1)		(1,686	)		(2,362	)
Summit Holdings’ 5.75% senior unsecured notes due April 2025		500,000			500,000
Less unamortized debt issuance costs (1)		(5,015	)		(5,907	)
SMP Holdings’ variable rate senior secured term loan ( 7.80% at December 31, 2019 and 8.52% at December 31, 2018) due May 2022		161,500			226,750
Less unamortized debt issuance costs (1)		(3,974	)		(5,701	)
Total debt		1,627,825			1,478,780
Less current portion		5,546			14,500
Total long-term debt	$	1,622,279		$	1,464,280

(1) Issuance costs are being amortized over the life of the Term Loan B and Senior Notes.

The aggregate amount of debt maturing during each of the years after December 31, 2019 are as follows (in thousands):

2020	$	—
2021		—
2022		1,138,500
2023		—
2024		—
Thereafter		500,000
Total long-term debt	$	1,638,500

Revolving Credit Facility.

Summit Holdings has a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. As of December 31, 2019, SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of, the indebtedness outstanding under the Revolving Credit Facility.

In May 2017, Summit Holdings amended and restated its Revolving Credit Facility with a third amended and restated credit agreement which: (i) maintained the Revolving Credit Facility commitments of $1.25 billion, (ii) extended the maturity from November 2018 to May 2022, (iii) included a $250.0 million accordion feature, (iv) maintained the same leverage-based pricing and commitment fee grid, (v) increased the maximum permitted total leverage ratio, as defined in the credit agreement, from 5.00 to 1.00 to 5.50 to 1.00 and (vi) included a maximum permitted senior secured leverage ratio, as defined in the credit agreement, of 3.75 to 1.00. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the transactions contemplated by the Agreement and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility. In December 2019, we executed the third amendment to the third amended and restated credit agreement that, among other things, designated the

Non-Guarantor

Subsidiaries as unrestricted subsidiaries under the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 1.75% or the adjusted Eurodollar rate (as defined in the credit agreement) plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At December 31, 2019, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 4.55% and the unused portion of the Revolving Credit Facility totaled $563.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2019 was approximately $100 million. See Note 16 for additional information on our letter of credit.

EX 99.3-28

The Revolving Credit Facility is secured by the membership interests of Summit Holdings and the membership interests of the Guarantor Subsidiaries of Summit Holdings and by substantially all of the assets of Summit Holdings and its Guarantor Subsidiaries (subject to exclusions set forth in the credit agreement). The credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability (i) to incur additional debt; (ii) to make investments; (iii) to engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) to enter into swap agreements and power purchase agreements; (v) to enter into leases that would cumulatively obligate payments in excess of $50.0 million over any 12 -month period; and (vi) of Summit Holdings to make distributions, with certain exceptions, including the distribution of Available Cash (as defined in the SMLP Partnership Agreement) if no default or event of default then exists or would result therefrom and Summit Holdings is in pro forma compliance with its financial covenants. In addition, the Revolving Credit Facility requires Summit Holdings to maintain (i) a ratio of consolidated trailing 12 -month earnings before interest, income taxes, depreciation and amortization (“EBITDA”) to net interest expense of not less than 2.5 to 1.0 as defined in the credit agreement, (ii) a ratio of total net indebtedness to consolidated trailing 12 -month EBITDA of not more than 5.50 to 1.00 and, (iii) a ratio of first lien net indebtedness to consolidated trailing 12 -month EBITDA of not more than 3.75 to 1.00.

As of December 31, 2019, we had $6.2 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in Other noncurrent assets on the consolidated balance sheet.

As of December 31, 2019, we were in compliance with the Revolving Credit Facility’s financial covenants. There were no defaults or events of default during the year ended December 31, 2019.

Senior Notes.

In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the

“Co-Issuers”)

co-issued

$300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the “5.5% Senior Notes” and, together with the 5.75% Senior Notes (defined below), the “Senior Notes”).

In 2018, we executed supplemental indentures to include OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream (through March 22, 2019) as guarantors concurrent with the purchase of a 1% noncontrolling interest held by a subsidiary of Summit Investments (see Note 12 to the consolidated financial statements for additional details). In 2019, we executed a partial release agreement that designated the

Non-Guarantor

Subsidiaries as unrestricted subsidiaries under the Senior Notes.

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

Co-Issuers.

5.75% Senior Notes

. In February 2017, the

Co-Issuers

completed a public offering of $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025. We pay interest on the 5.75% Senior Notes semi-annually in cash in arrears on April 15 and October 15 of each year. The 5.75% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.75% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility.

At any time prior to April 15, 2020, the

Co-Issuers

may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.750% of the principal amount of the 5.75% Senior Notes, plus accrued and unpaid interest, if any, but not including, the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after April 15, 2020, the

Co-Issuers

may redeem all or part of the 5.75% Senior Notes at a redemption price of 104.313% (with the redemption premium declining ratably each year to 100.000% on and after April 15, 2023), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs of $7.7 million are being amortized over the life of the 5.75% Senior Notes.

EX 99.3-29

The 5.75% Senior Notes’ indenture restricts SMLP’s and the

Co-Issuers’

ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate.

The 5.75% Senior Notes’ indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.75% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.75% Senior Notes; (iii) failure by the

Co-Issuers

or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the

Co-Issuers

or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $75.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.75% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.75% Senior Notes may declare all the 5.75% Senior Notes to be due and payable immediately.

5.5% Senior Notes

. We pay interest on the 5.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year. The 5.5% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.5% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.5% Senior Notes to repay a portion of the balance outstanding under our Revolving Credit Facility.

At any time prior to August 15, 2020, the

Co-Issuers

may redeem all or part of the 5.5% Senior Notes at a redemption price of 101.375% (with the redemption premium declining to 100.000% on and after August 15, 2020), plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 5.5% Senior Notes.

The 5.5% Senior Notes’ indenture restricts SMLP’s and the

Co-Issuers’

ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate.

The 5.5% Senior Notes’ indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.5% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.5% Senior Notes; (iii) failure by the

Co-Issuers

or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to

EX 99.3-30

comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the

Co-Issuers

or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $20.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.5% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.5% Senior Notes may declare all the 5.5% Senior Notes to be due and payable immediately.

As of and during the December 31, 2019, we were in compliance with the financial covenants governing our Senior Notes. There were no defaults or events of default during the year ended December 31, 2019.

SMP Holdings Term Loan.

On March 21, 2017, SMP Holdings closed on a $300.0 million senior secured term loan facility, (the “Term Loan B”) with the maturity date of May 15, 2022. Borrowings under the Term Loan B bear interest at LIBOR plus 6.00% or ABR plus 5.00%, as defined in the Term Loan B credit agreement. At December 31, 2019, the applicable margin under LIBOR borrowings was 6.00% and the interest rate was 7.80%.

The Term Loan B contains certain customary negative covenants, including but not limited to, limitations on the incurrence of debt, limitations on liens, limitations on asset sales and sale leasebacks, limitations on investments, limitations on dividends, limitations on distributions, limitations on prepayments, and limitations on transactions with affiliates. The Term Loan B also includes a maintenance covenant consisting of a minimum interest coverage ratio whereby the Company is required to maintain a ratio of operating cash flow less general and administrative expenses paid to cash interest expense for the test period (as defined in the Term Loan B credit agreement) of not less than 2.0 to 1.0.

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

At December 31, 2019, the Term Loan B is secured by the following collateral): (i) a perfected first-priority lien on, and pledge of (A) all of the capital stock issued by SMP Holdings, (B) 34.6 million SMLP units owned by SMP Holdings (see Note 13), (C) all of the equity interests owned by SMP Holdings in Summit Midstream GP, LLC, which is the general partner of SMLP, and (ii) substantially all other personal property of SMP Holdings.

Loans under the Term Loan B must be prepaid under certain circumstances, including with proceeds from certain future debt issuances, asset sales and a portion of excess cash flow for the applicable fiscal quarter. Loans under the Term Loan B may be voluntarily prepaid at any time, subject to certain redemption prices and customary LIBOR breakage costs.

SMP Holdings is required to repay principal amounts outstanding under the Term Loan B quarterly, based on a fixed amortization schedule and to prepay its debt obligations based on an excess cash flow calculation for the applicable fiscal quarter which is determined in accordance with the terms of the Term Loan B credit agreement. The Company’s current portion of long-term debt, which includes scheduled principal amortization and excess cash flow prepayments, includes $2.5 million with respect to its fourth quarter 2019 required excess cash flow payment which will be paid within the second quarter of 2020. We have not included an estimated excess cash flow amount in the current portion of long-term debt relating to the first, second and third quarter of 2020 because the amount is not currently estimable given that the excess cash flow calculation is based on the occurrence of future events.

EX 99.3-31

As a result of the Term Loan B, the Company incurred approximately $8.7 million of debt issuance

costs

. As of December 31, 2019, the Company was in compliance the Term Loan B’s financial covenants. There were no defaults or events of default during the year ended December 31, 2019.

11. FINANCIAL INSTRUMENTS

Concentrations of Credit Risk.

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

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

Fair Value.

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

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

	December 31, 2019				December 31, 2018
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings 5.5% Senior Notes ($300.0 million principal)	$	298,314	$	266,750	$	297,638	$	286,625
Summit Holdings 5.75% Senior Notes ($500.0 million principal)		494,985		382,708		494,093		455,208

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

12. PARTNERS’ CAPITAL AND MEZZANINE CAPITAL

As a result of the GP

Buy-In

Transaction, our historical results are those of Summit Investments. The number of common units of 45.3 million represents those of Summit Investments and has been used for the earnings per unit calculations presented herein.

SMLP General Partner and Incentive Distribution Rights (“IDR”) Exchange.

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

DPPO Partial Settlement.

In November 2019, and prior to the GP Buy-In Transaction, a subsidiary of Summit Investments amended its deferred purchase price obligation (“DPPO”) with SMLP in exchange for a cash payment of $51.75 million and 10,714,285 SMLP common units. This partial settlement of the DPPO is reflected in the Consolidated Statements of Partners’ Capital as a reduction to noncontrolling interest and an increase to Partners’ Capital.

Unit Offerings.

In February 2017, we completed a secondary underwritten public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments pursuant to the 2016 SRS. We did not receive any proceeds from this offering.

At-the-market

Program.

In February 2017, we executed a new equity distribution agreement and filed a prospectus with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the “ATM Program”). During the years ended December 31, 2019 and 2018, there were no transactions under the ATM Program. During the year ended December 31, 2017, we sold 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement.

Series A Preferred Units.

In November 2017, we issued 300,000 Series A

Fixed-to-Floating

Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. We used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under our Revolving Credit Facility.

EX 99.3-32

The Series A Preferred Units rank senior to (i) common units representing limited partner interests in the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that expressly ranks junior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Series A Preferred Units rank equal in all respects with each class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that is not expressly made senior or subordinated to the Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Series A Preferred Units rank junior to (i) all of the Partnership’s existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership established in the future that is expressly made senior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Series A Preferred Units in an amount equal to the earned distributions for the respective reporting period.

Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose.

The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%.

Subsidiary Series A Preferred Units.

In December 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $27.4 million (after deducting underwriting discounts and offering expenses) to fund capital expenses associated with the Double E Project.

On January 16, 2020, we issued 10,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $9.7 million (after deducting underwriting discounts and offering expenses) to fund capital expenses associated with the Double E Project.

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

Accounting for the Subsidiary Series A Preferred Units

These preferred units are considered redeemable securities under GAAP due to the existence of certain redemption provisions that are outside of our control. Therefore, the securities are classified as temporary equity in the mezzanine section of the consolidated balance sheet.

Initial and Subsequent Measurement

We initially recognized these preferred units at the time of issuance in the amount of $27.4 million, their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of these preferred units unless it becomes probable that the units would become redeemable. If events or circumstances indicate that redemption is probable, we would accrete these preferred units to the redemption value over a period of time comprising the date redemption first became probable and the date the units can first be redeemed.

The Subsidiary Series A Preferred Units rank senior to each other class or series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that expressly ranks junior to the Subsidiary

EX 99.3-33

Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Subsidiary Series A Preferred Units rank equal in all respects with each class or series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that is not expressly made senior or subordinated to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Subsidiary Series A Preferred Units rank junior to (i) all of Permian Holdco’s or a subsidiary of Permian Holdco’s future indebtedness and other liabilities with respect to assets available to satisfy claims against Permian Holdco and (ii) each other class or series of limited partner interests or other equity securities in Permian Holdco established in the future that is expressly made senior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Subsidiary Series A Preferred Units in an amount equal to the earned distributions for the respective reporting period.

Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable 21 days following the quarterly period ended March, June, September and December of each year (each, a “Series A Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Series A Distribution Payment Date, in each case, when, as, and if declared by Permian Holdco out of legally available funds for such purpose.

The distribution rate for the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 liquidation preference per Subsidiary Series A Preferred Unit. A

pro-rated

initial distribution on the Subsidiary Series A Preferred Units was

Paid-in-kind

(“PIK”) on January 21, 2020 in an amount equal to 7.00% per Subsidiary Series A Preferred Unit plus 1.00% per annum of the undrawn commitment units.

Cash Distribution Policy

Our Partnership Agreement requires that we distribute all of our available cash, subject to reserves established by our 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 our policy is subject to fluctuations based on the amount of cash we generate from our business and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.

Cash Distributions Paid and Declared.

Prior to the GP Buy-In Transaction, SMLP paid the following

per-unit

distributions during the years ended December 31 (All payments represent per-unit distributions based on the SMLP common units outstanding prior to the GP

Buy-In

Transaction):

	Year ended December 31,
	2019		2018		2017
Per-unit distributions to unitholders	$	1.4375	$	2.300	$	2.300

On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit for the quarterly period ended December 31, 2019. This distribution, which totaled $11.7 million, was paid on February 14, 2020 to unitholders of record at the close of business on February 7, 2020.

With respect to our Subsidiary Series A Preferred Units relating to the fourth quarter of 2019, we declared a

payment-in-kind

(“PIK”) of the quarterly distribution, which resulted in the

pro-rated

issuance of 47 Subsidiary Series A Preferred Units. This PIK amount equates to a

pro-rated

distribution of $1.5556 per Subsidiary Series A Preferred Unit for the fourth quarter in 2019, or $70 on a full year annualized basis.

EX 99.3-34

13. EARNINGS PER UNIT

The following table details the components of EPU.

	Year ended December 31,
	2019			2018		2017
	(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
Allocation of net (loss) income among limited partner interests:
Net (loss) income attributable to limited partners	$	(184,451	)	$	31,546	$	(183,411	)
Less net income attributable to Series A Preferred Units		28,500			28,500		3,563
Less net income attributable to Subsidiary Series A Preferred Units		58			—		—
Net (loss) income attributable to common limited partners	$	(213,009	)	$	3,046	$	(186,974	)
Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic (1)		45,319			45,319		45,319
Effect of nonvested phantom units		—			311		—
Weighted-average common units outstanding – diluted		45,319			45,630		45,319
(Loss) earnings per limited partner unit:
Common unit – basic	$	(4.70	)	$	0.07	$	(4.13	)
Common unit – diluted	$	(4.70	)	$	0.07	$	(4.13	)
Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		175			2		42

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

As discussed in Note 10, the Term Loan B is secured by 34.6 million SMLP units owned by SMP Holdings. These common units have not been included in the calculation of EPU because they are not deemed contingently issuable under GAAP.

14. UNIT-BASED AND NONCASH COMPENSATION

SMP Net Profits Interests.

In connection with the formation of Summit Investments in 2009, up to 7.5% of total membership interests were authorized for issuance, of which 6.355% had been granted to certain current and former members of management. SMP Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets. The SMP Net Profits Interests were accounted for as compensatory awards. Additional SMP Net Profits Interests were granted through January 2012. All grants vested ratably over five years and provided for accelerated vesting in certain limited circumstances.

As of December 31, 2019, 4.2% of SMP Net Profits Interests were vested and outstanding. There were no nonvested SMP Net Profits Interests as of December 31, 2019 and 2018.

SMLP Long-Term Incentive Plan.

The SMLP LTIP provides for equity awards to eligible officers, employees, consultants and directors of our General Partner and its affiliates, thereby linking the recipients’ compensation directly to SMLP’s performance. The SMLP LTIP is administered by our General Partner’s Board of Directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2019, approximately 1.3 million common units remained available for future issuance.

The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the Board of Directors or Compensation Committee of our General Partner. The administrator of the SMLP LTIP may make grants under the SMLP LTIP that contain such terms, consistent with the SMLP LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the SMLP LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the SMLP LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards.

EX 99.3-35

The following table presents phantom unit activity:

	Units			Weighted-average grant date fair value
Nonvested phantom units, January 1, 2017		691,955		$	19.59
Phantom units granted		371,972			22.50
Phantom units vested		(293,222	)		24.76
Phantom units forfeited		(21,431	)		20.07
Nonvested phantom units, December 31, 2017		749,274			20.07
Phantom units granted		515,358			15.25
Phantom units vested		(359,016	)		22.39
Phantom units forfeited		(41,492	)		17.27
Nonvested phantom units, December 31, 2018		864,124			17.11
Phantom units granted		1,913,099			6.48
Phantom units vested		(602,617	)		16.78
Phantom units forfeited		(68,611	)		12.87
Nonvested phantom units, December 31, 2019		2,105,995		$	7.69

A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date.

Phantom units granted to date generally vest ratably over a three-year period. Grant date fair value is determined based on the closing price of our common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Forfeitures are recorded as incurred. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at our discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units.

The intrinsic value of phantom units that vested during the years ended December 31, follows.

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Intrinsic value of vested LTIP awards	$	5,940	$	5,393	$	6,657

As of December 31, 2019, the unrecognized unit-based compensation related to the SMLP LTIP was $8.5 million. Incremental unit-based compensation will be recorded over the remaining weighted-average vesting period of approximately 1.6 years.

Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows.

	Year ended December 31,
	2019		2018		2017
	(In thousands)
SMLP LTIP unit-based compensation	$	8,171	$	8,328	$	7,951

15.

RELATED-PARTY

TRANSACTIONS

See Note 12 for disclosure of related partners’ capital and mezzanine capital issuances.

EX 99.3-36

16. LEASES, COMMITMENTS AND CONTINGENCIES

Leases.

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

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

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

We have options to extend the lease term of certain office space in Texas, Colorado and West Virginia. The beginning of the noncancelable lease period for these leases ranged from 2014 to 2018 and the lease period ends between 2020 and 2028. These lease agreements contain between one and three options to renew the lease for a period of between two and five years. As of December 31, 2019, the exercise of the renewal options for these leases are not reasonably certain and, as a result, the payments associated with these renewals are not included in the measurement of the lease liability and ROU asset.

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

Our leases do not contain residual value guarantees.

In accordance with the provisions in our Revolving Credit Facility, our aggregate finance lease obligations cannot exceed $50 million in any period of twelve consecutive calendar months during the life of such leases. In accordance with the provisions in our Term Loan B, our aggregate finance lease obligations cannot exceed $5 million.

In November 2019, we entered into a sublease agreement with a third party to sublease corporate office space in Houston, Texas. The noncancelable sublease period begins in 2020 and the sublease period ends in 2025. The sublease agreement contains one option to renew the lease for five years. We moved our corporate headquarters to the Houston office on March 2, 2020. Our future minimum sublease payments are approximately $1.2 million.

In March 2019, we entered into an agreement with a third party vendor to construct a transmission line to deliver electric power to the new 60 MMcf/d processing plant in the DJ Basin. The project is expected to cost approximately $7.8 million and we made an

up-front

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

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

The rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term

EX 99.3-37

used. Our incremental borrowing rate on the Revolving Credit Facility was 4.55% at December 31, 2019, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.

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

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

	December 31,
	2019
	(In thousands)
ROU assets
Operating	$	3,580
Finance		3,159
	$	6,739
Lease liabilities, current
Operating	$	1,221
Finance		1,246
	$	2,467
Lease liabilities, noncurrent
Operating	$	2,513
Finance		676
	$	3,189

Lease cost and Other information follow:

	Year ended December 31, 2019
	(In thousands)
Lease cost
Finance lease cost:
Amortization of ROU assets (included in depreciation and amortization)	$	1,559
Interest on lease liabilities (included in interest expense)		102
Operating lease cost (included in general and administrative expense)		3,345
	$	5,006

EX 99.3-38

	Twelve months ended
	December 31, 2019
	(In thousands)
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash outflows from operating leases	$	3,396
Operating cash outflows from finance leases		102
Financing cash outflows from finance leases		1,873
ROU assets obtained in exchange for new operating lease liabilities		1,218
ROU assets obtained in exchange for new finance lease liabilities		1,350
Weighted-average remaining lease term (years) - operating leases		5.8
Weighted-average remaining lease term (years) - finance leases		2.0
Weighted-average discount rate - operating leases		5	%
Weighted-average discount rate - finance leases		4	%

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

	Year ended December 31,
	2019		2018		2017
	(In thousands)
Lease expense	$	4,038	$	4,108	$	3,963

Future minimum lease payments due under noncancelable leases at December 31, 2019, were as follows

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

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

	December 31,
	2018
	(In thousands)
2019	$	3,133
2020		1,018
2021		550
2022		506
2023		373
Thereafter		621
Total future minimum lease payments	$	6,201

EX 99.3-39

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

	December 31,
	2018
	(In thousands)
2019	$	1,473
2020		902
2021		174
Total finance lease obligations		2,549
Less: Amounts representing interest		(104	)
Net present value of finance lease obligations		2,445
Less: Amount representing current portion (included in Other current liabilities)		(1,406	)
Finance lease obligations, less current portion (included in Other noncurrent liabilities)	$	1,039

Environmental Matters.

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

In 2015, we learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, which was covered by our insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. We exhausted the $25.0 million pollution liability policy in 2015. We submitted property and business interruption claim requests to the insurers and reached a settlement in January 2017. In connection therewith, we recognized $2.6 million of business interruption recoveries and $0.4 million of property recoveries.

A rollforward of the aggregate accrued environmental remediation liabilities follows.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2018	$	5,344
Payments made		(3,808	)
Additional accruals		4,100
Accrued environmental remediation, December 31, 2018	$	5,636
Payments made		(2,284	)
Additional accruals		1,299
Accrued environmental remediation, December 31, 2019	$	4,651

As of December 31, 2019, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to December 31, 2020. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

While we cannot predict the ultimate outcome of this matter with certainty for the Partnership or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident, we believe at this time that it is unlikely that the Partnership will be subject to any material liability as a result of any governmental proceeding related to the rupture. Prior to the GP

Buy-In

Transaction, Summit Midstream Partners Holdings, LLC, a subsidiary of Summit Investments, had certain indemnity obligations to the Partnership associated with the 2016 sale of Meadowlark Midstream to the Partnership.

Legal Proceedings.

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

EX 99.3-40

17. DISPOSITIONS, DROP DOWN TRANSACTIONS AND RESTRUCTURING

Red Rock Gathering Asset Disposition.

In December 2019, Red Rock Gathering and certain affiliates of SMLP (collectively, “the Red Rock Parties”) entered into a Purchase and Sale Agreement (the “Red Rock PSA”) pursuant to which the Red Rock Parties agreed to sell certain Red Rock Gathering system assets for a cash purchase price of $12.0 million, subject to adjustments as provided in the Red Rock PSA (the “Red Rock Sale”). Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. On December 2, 2019, we closed the Red Rock Sale. The impairment is included in the Long-lived asset impairment caption on the consolidated statement of operations. The financial contribution of these assets (a component of the Piceance Basin reportable segment) are included in our consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

Tioga Midstream Disposition.

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

Restructuring Activities.

In 2019, our management approved and initiated a plan to restructure our operations resulting in certain management, facility and organizational changes. During the year ended December 31, 2019, we expensed costs of approximately $5.0 million associated with restructuring activities. These activities consisted primarily of employee-related costs and consulting costs in support of the project. These costs are included within the General and administrative caption on the consolidated statement of operations.

As of December 31, 2019, the components of our restructuring plan are as follows:

• Employee-related costs — we reorganized our workforce and eliminated redundant or unneeded positions. In connection with the workforce restructuring, we expect to incur severance, benefits and other employee related costs of approximately $6.0 million to be incurred over the twelve months following December 31, 2019. During the fiscal year ended December 31, 2019, we expensed approximately $3.8 million primarily related to severance, redundant salaries, certain bonuses and other employee benefits in connection with our plan. As of December 31, 2019, we had approximately $2.7 million included in current liabilities for these costs.

EX 99.3-41

• Consultants — we engaged third-party consulting firms to assist in the evaluation of the Company’s cost structure, to help formulate the plan to implement the project, and to provide project management services for certain project initiatives. During the fiscal year ended December 31, 2019, we expensed approximately $1.2 million related to these services. As of December 31, 2019, we had approximately $0.6 million included in current liabilities for these costs. We expect to incur an additional $0.2 million related to consulting costs to be incurred over the next twelve months following December 31, 2019.

18. UNAUDITED QUARTERLY FINANCIAL DATA

Summarized information on the consolidated results of operations for each of the quarters during the

two-year

period ended December 31, 2019, follows.

	Quarter ended
	December 31, 2019			September 30, 2019			June 30, 2019			March 31, 2019
	(In thousands, except per-unit amounts)
Total revenues	$	112,247		$	100,187		$	99,686		$	131,408
Net (loss) income attributable to SMLP	$	(345,345	)	$	(11,129	)	$	3,028		$	(40,280	)
Less net loss attributable to noncontrolling interest		(172,024	)		(10,340	)		(1,341	)		(25,570	)
Less net income attributable to Series A Preferred Units		7,125			7,125			7,125			7,125
Less net income attributable to Subsidiary Series A Preferred Units		58			—			—			—
Net loss attributable to common limited partners	$	(180,504	)	$	(7,914	)	$	(2,756	)	$	(21,835	)
Loss per limited partner unit:
Common unit - basic	$	(3.98	)	$	(0.17	)	$	(0.06	)	$	(0.48	)
Common unit - diluted	$	(3.98	)	$	(0.17	)	$	(0.06	)	$	(0.48	)

	Quarter ended
	December 31, 2018			September 30, 2018			June 30, 2018			March 31, 2018
	(In thousands, except per-unit amounts)
Total revenues	$	133,671		$	127,479		$	128,183		$	117,320
Net (loss) income attributable to SMLP	$	(3,401	)	$	14,353		$	11,861		$	11,507
Less net income (loss) attributable to noncontrolling interest		18,535			30,453			(37,712	)		(8,502	)
Less net income attributable to Series A Preferred Units		7,125			7,125			7,125			7,125
Net (loss) income attributable to common limited partners	$	(29,061	)	$	(23,225	)	$	42,448		$	12,884
(Loss) earnings per limited partner unit:
Common unit - basic	$	(0.64	)	$	(0.51	)	$	0.94		$	0.28
Common unit - diluted	$	(0.64	)	$	(0.51	)	$	0.93		$	0.28

EX 99.3-42

19. SUBSEQUENT EVENTS

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

On May 28, 2020, the Partnership closed on the Purchase Agreement and acquired (i) all the outstanding limited liability company interests of Summit Investments, which is the sole member of SMP Holdings, which in turn owns (a) 34,604,581 common units representing limited partner interests in the Partnership (the “Common Units”) pledged as collateral under the Term Loan B, (b) 10,714,285 Common Units not pledged as collateral under the Term Loan B and (c) the right of SMP Holdings to receive the deferred purchase price obligation under the Contribution Agreement by and between the Partnership and SMP Holdings, dated February 25, 2016, as amended, and (ii) 5,915,827 Common Units held by SMLP Holdings, LLC, a Delaware limited liability company and an affiliate of ECP. The total purchase price under the Purchase Agreement was $35 million in cash and warrants to purchase up to 10 million Common Units. Pursuant to the Purchase Agreement, SMP Holdings will continue to retain the liabilities stemming from the release of produced water, from a produced water pipeline operated by Meadowlark Midstream Company, LLC that occurred near Marmon, North Dakota and was reported on January 6, 2015. We refer to the transactions contemplated by the Purchase Agreement as the “GP Buy-In Transaction.”

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

Upon closing of the GP Buy-In Transaction, all directors affiliated with ECP resigned from the Board of Directors. The Board of Directors now consists of a majority of independent directors. Additionally, the Third Amended and Restated Agreement of Limited Partnership of the Partnership was amended and restated, and the Amended and Restated Limited Liability Company Agreement of Partnership’s general partner was amended and restated, to, among other things, provide the holders of common units with voting rights in the election of directors of the Board of Directors on a staggered basis beginning in 2022.

EX 99.3-43