enlc-20200630

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2020

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)


Delaware			46-4108528
(State of organization)			(I.R.S. Employer Identification No.)

1722 Routh St., Suite 1300
Dallas,	Texas	75201
(Address of principal executive offices)			(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE SECURITIES EXCHANGE ACT OF 1934:

Title of Each Class

Trading Symbol

Name of Exchange on which Registered

Common Units Representing Limited

ENLC

The New York Stock Exchange

Liability Company Interests

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

As of July 30, 2020, the Registrant had 489,593,387 common units outstanding.

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TABLE OF CONTENTS


Item	Description	Page

	PART I—FINANCIAL INFORMATION

1.	Financial Statements	5

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

3.	Quantitative and Qualitative Disclosures About Market Risk	50

4.	Controls and Procedures	53

	PART II—OTHER INFORMATION

1.	Legal Proceedings	54

1A.	Risk Factors	54

2.	Unregistered Sales of Equity Securities and Use of Proceeds	54

6.	Exhibits	55

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DEFINITIONS

The following terms as defined are used in this document:


Defined Term						Definition
/d						Per day.
2014 Plan						ENLC’s 2014 Long-Term Incentive Plan.

ASC						The FASB Accounting Standards Codification.
ASC 350						ASC 350, Intangibles—Goodwill and Other.
ASC 842						ASC 842, Leases.
Ascension JV						Ascension Pipeline Company, LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Marathon Petroleum Corporation in which ENLK owns a 50% interest and Marathon Petroleum Corporation owns a 50% interest. The Ascension JV, which began operations in April 2017, owns an NGL pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
ASU						The FASB Accounting Standards Update.

Bbls						Barrels.
Bcf						Billion cubic feet.
Cedar Cove JV						Cedar Cove Midstream LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Kinder Morgan, Inc. in which ENLK owns a 30% interest and Kinder Morgan, Inc. owns a 70% interest. The Cedar Cove JV, which was formed in November 2016, owns gathering and compression assets in Blaine County, Oklahoma, located in the STACK play.
CFTC						U.S. Commodity Futures Trading Commission.
CNOW						Central Northern Oklahoma Woodford Shale.
Commission						U.S. Securities and Exchange Commission.
Consolidated Credit Facility						A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility.
Delaware Basin						A large sedimentary basin in West Texas and New Mexico.
Delaware Basin JV						Delaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities and the Tiger Plant located in the Delaware Basin in Texas.
Devon						Devon Energy Corporation.

ENLC						EnLink Midstream, LLC.

ENLC Credit Facility						A $250.0 million secured revolving credit facility entered into by ENLC that would have matured on March 7, 2019, which included a $125.0 million letter of credit subfacility. The ENLC Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.

ENLK						EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”


FASB						Financial Accounting Standards Board.
GAAP						Generally accepted accounting principles in the United States of America.
Gal						Gallons.
GCF						Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
General Partner						EnLink Midstream GP, LLC, the general partner of ENLK.
GIP						Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.

GP Plan						The General Partner’s Long-Term Incentive Plan.

Gross Operating Margin						Revenue less cost of sales. Gross Operating Margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information.
ISDAs						International Swaps and Derivatives Association Agreements.
Legacy ENLK Awards						Unit-based awards granted under the GP Plan prior to the Merger. As of the closing of the Merger, Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio from the Merger Agreement as the conversion rate. No additional awards will be granted under the GP Plan.

Managing Member						EnLink Midstream Manager, LLC, the managing member of ENLC.
Merger						On January 25, 2019, NOLA Merger Sub, LLC (previously a wholly-owned subsidiary of ENLC) merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.

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Merger Agreement						The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, the General Partner, ENLC, the Managing Member, and NOLA Merger Sub, LLC (previously a wholly-owned subsidiary of ENLC prior to the Merger) related to the Merger.
MMbbls						Million barrels.
MMbtu						Million British thermal units.
MMcf						Million cubic feet.
MVC						Minimum volume commitment.
NGL						Natural gas liquid.
NGP						NGP Natural Resources XI, LP.

OPEC+						Organization of the Petroleum Exporting Countries and its broader partners.
Operating Partnership						EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
ORV						ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTC						Over-the-counter.

POL contracts						Percentage-of-liquids contracts.
POP contracts						Percentage-of-proceeds contracts.
Series B Preferred Units						ENLK’s Series B Cumulative Convertible Preferred Units.
Series C Preferred Units						ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
STACK						Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan						An $850.0 million term loan entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guarantees.

Tiger Plant						A gas processing plant that is under construction in the Delaware Basin and is owned by the Delaware Basin JV.
White Star						White Star Petroleum, LLC.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


	June 30, 2020		December 31, 2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	52.0	$	77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.5, respectively	82.0		36.2
Accrued revenue and other	304.7		460.1

Fair value of derivative assets	9.9		12.9
Other current assets	58.6		57.8
Total current assets	507.2		644.4
Property and equipment, net of accumulated depreciation of $3,654.7 and $3,418.6, respectively	6,828.7		7,081.3
Intangible assets, net of accumulated amortization of $607.1 and $545.9, respectively	1,187.1		1,249.9
Goodwill	—		184.6
Investment in unconsolidated affiliates	42.1		43.1
Fair value of derivative assets	5.8		4.3
Other assets, net	147.9		128.2
Total assets	$	8,718.8	$	9,335.8
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	49.4	$	70.6
Accounts payable to related party	0.4		1.1
Accrued gas, NGLs, condensate, and crude oil purchases	188.8		354.8
Fair value of derivative liabilities	31.3		14.4

Other current liabilities	160.2		206.2
Total current liabilities	430.1		647.1
Long-term debt	4,749.0		4,764.3
Asset retirement obligations	15.9		15.5
Other long-term liabilities	84.8		90.8

Fair value of derivative liabilities	9.4		6.8

Redeemable non-controlling interest	—		5.2

Members’ equity:
Members’ equity (489,463,987 and 487,791,612 units issued and outstanding, respectively)	1,728.5		2,135.5
Accumulated other comprehensive loss	(22.6)		(11.0)
Non-controlling interest	1,723.7		1,681.6
Total members’ equity	3,429.6		3,806.1
Total liabilities and members’ equity	$	8,718.8	$	9,335.8

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(Unaudited)
Revenues:
Product sales	$	532.6	$	1,450.4	$	1,425.5	$	2,981.3

Midstream services	234.7		252.7		478.7		499.2

Gain (loss) on derivative activity	(22.4)		6.9		(3.2)		8.7
Total revenues	744.9		1,710.0		1,901.0		3,489.2
Operating costs and expenses:
Cost of sales	397.7		1,300.1		1,153.0		2,663.5
Operating expenses	88.1		117.9		188.8		232.4
General and administrative	23.5		32.2		53.9		83.6
Loss on disposition of assets	5.2		0.1		4.6		0.1
Depreciation and amortization	158.2		153.7		321.0		305.8
Impairments	1.5		—		354.5		186.5
Loss on secured term loan receivable	—		52.9		—		52.9

Total operating costs and expenses	674.2		1,656.9		2,075.8		3,524.8
Operating income (loss)	70.7		53.1		(174.8)		(35.6)
Other income (expense):
Interest expense, net of interest income	(55.2)		(54.3)		(110.8)		(103.9)
Gain on extinguishment of debt	26.7		—		32.0		—
Income (loss) from unconsolidated affiliates	(0.7)		4.7		1.0		10.0
Other income	—		0.2		—		0.2
Total other expense	(29.2)		(49.4)		(77.8)		(93.7)
Income (loss) before non-controlling interest and income taxes	41.5		3.7		(252.6)		(129.3)
Income tax benefit (expense)	(11.7)		5.4		22.0		3.6
Net income (loss)	29.8		9.1		(230.6)		(125.7)
Net income attributable to non-controlling interest	25.7		25.2		52.1		66.7
Net income (loss) attributable to ENLC	$	4.1	$	(16.1)	$	(282.7)	$	(192.4)
Net income (loss) attributable to ENLC per unit:
Basic common unit	$	0.01	$	(0.03)	$	(0.58)	$	(0.44)
Diluted common unit	$	0.01	$	(0.03)	$	(0.58)	$	(0.44)

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(In millions)


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(Unaudited)
Net income (loss)	$	29.8	$	9.1	$	(230.6)	$	(125.7)
Gain (loss) on designated cash flow hedge (1)	1.5		(9.9)		(11.6)		(9.9)
Comprehensive income (loss)	31.3		(0.8)		(242.2)		(135.6)
Comprehensive income attributable to non-controlling interest	25.7		25.2		52.1		66.7
Comprehensive income (loss) attributable to ENLC	$	5.6	$	(26.0)	$	(294.3)	$	(202.3)

____________________________

(1)Includes a tax expense of $0.5 million and a tax benefit of $3.5 million for the three and six months ended June 30, 2020, respectively, and a tax benefit of $3.6 million for the three and six months ended June 30, 2019, respectively.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

(In millions)


	Common Units					Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-controlling interest (Temporary Equity)
	$		Units	$		$		$		$
	(Unaudited)
Balance, December 31, 2019	$	2,135.5	487.8	$	(11.0)	$	1,681.6	$	3,806.1	$	5.2
Conversion of restricted units for common units, net of units withheld for taxes	(4.0)		1.3	—		—		(4.0)		—
Unit-based compensation	12.3		—	—		—		12.3		—
Contributions from non-controlling interests	—		—	—		37.1		37.1		—
Distributions	(93.3)		—	—		(24.4)		(117.7)		(0.3)
Loss on designated cash flow hedge (1)	—		—	(13.1)		—		(13.1)		—
Redemption of non-controlling interest	—		—	—		—		—		(4.0)
Fair value adjustment related to redeemable non-controlling interest	0.7		—	—		—		0.7		(0.9)
Net income (loss)	(286.8)		—	—		26.4		(260.4)		—
Balance, March 31, 2020	1,764.4		489.1	(24.1)		1,720.7		3,461.0		—
Conversion of restricted units for common units, net of units withheld for taxes	(0.3)		0.4	—		—		(0.3)		—
Unit-based compensation	6.8		—	—		—		6.8		—
Contributions from non-controlling interests	—		—	—		13.2		13.2		—
Distributions	(46.5)		—	—		(35.9)		(82.4)		—
Gain on designated cash flow hedge (2)	—		—	1.5		—		1.5		—


Net income	4.1		—	—		25.7		29.8		—
Balance, June 30, 2020	$	1,728.5	489.5	$	(22.6)	$	1,723.7	$	3,429.6	$	—

____________________________

(1)Includes a tax benefit of $4.0 million.

(2)Includes a tax expense of $0.5 million.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity (Continued)

(In millions)


	Common Units					Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-Controlling Interest (Temporary Equity)
	$		Units	$		$		$		$
	(Unaudited)
Balance, December 31, 2018	$	1,730.9	181.3	$	(2.0)	$	3,245.3	$	4,974.2	$	9.3
Adoption of ASC 842	0.3		—	—		—		0.3		—
Balance, January 1, 2019	1,731.2		181.3	(2.0)		3,245.3		4,974.5		9.3
Conversion of restricted units for common units, net of units withheld for taxes	(5.6)		1.0	—		(2.8)		(8.4)		—
Unit-based compensation	12.2		—	—		1.4		13.6		—
Contributions from non-controlling interests	—		—	—		15.7		15.7		—
Distributions	(51.0)		—	—		(127.6)		(178.6)		—
Fair value adjustment related to redeemable non-controlling interest	2.5		—	—		—		2.5		(2.1)
Net income (loss)	(176.3)		—	—		41.5		(134.8)		—
Issuance of common units for ENLK public common units related to the Merger	1,958.1		304.9	—		(1,559.1)		399.0		—
Balance, March 31, 2019	3,471.1		487.2	(2.0)		1,614.4		5,083.5		7.2


Unit-based compensation	6.6		—	—		—		6.6		—
Contributions from non-controlling interests	—		—	—		29.5		29.5		—
Distributions	(137.2)		—	—		(35.1)		(172.3)		—
Loss on designated cash flow hedge (1)	—		—	(9.9)		—		(9.9)		—
Fair value adjustment related to redeemable non-controlling interest	0.2		—	—		—		0.2		(1.4)
Net income (loss)	(16.1)		—	—		25.2		9.1		—
Balance, June 30, 2019	$	3,324.6	487.2	$	(11.9)	$	1,634.0	$	4,946.7	$	5.8

____________________________

(1)Includes a tax benefit of $3.6 million.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)


	Six Months Ended June 30,
	2020		2019
	(Unaudited)
Cash flows from operating activities:
Net loss	$	(230.6)	$	(125.7)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairments	354.5		186.5
Depreciation and amortization	321.0		305.8
Loss on secured term loan receivable	—		52.9
Deferred income tax benefit	(22.7)		(4.9)


Non-cash unit-based compensation	16.2		19.1
(Gain) loss on derivatives recognized in net loss	3.2		(8.7)
Cash settlements on derivatives	2.8		4.9
Gain on extinguishment of debt	(32.0)		—
Amortization of debt issue costs, net discount (premium) of notes	2.2		2.9

Distribution of earnings from unconsolidated affiliates	1.2		9.7
Income from unconsolidated affiliates	(1.0)		(10.0)

Other operating activities	4.1		(3.0)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	109.8		270.7
Natural gas and NGLs inventory, prepaid expenses, and other	9.3		(7.4)
Accounts payable, accrued product purchases, and other accrued liabilities	(221.2)		(171.3)
Net cash provided by operating activities	316.8		521.5
Cash flows from investing activities:
Additions to property and equipment	(203.6)		(428.4)



Other investing activities	1.6		1.5
Net cash used in investing activities	(202.0)		(426.9)
Cash flows from financing activities:
Proceeds from borrowings	490.0		2,320.0
Payments on borrowings	(476.0)		(2,131.4)
Debt financing costs	—		(9.7)
Conversion of restricted units, net of units withheld for taxes	(4.3)		(8.4)
Distribution to members	(139.8)		(188.2)
Distributions to non-controlling interests	(60.6)		(162.7)
Contributions by non-controlling interests	50.3		45.2
Other financing activities	0.2		(0.8)
Net cash used in financing activities	(140.2)		(136.0)
Net decrease in cash and cash equivalents	(25.4)		(41.4)
Cash and cash equivalents, beginning of period	77.4		100.4
Cash and cash equivalents, end of period	$	52.0	$	59.0

Supplemental disclosures of cash flow information:
Cash paid for interest	$	106.6	$	103.7
Cash paid (refunded) for income taxes	$	(1.0)	$	1.2
Non-cash investing activities:
Non-cash accrual of property and equipment	$	(19.6)	$	(5.8)
Right-of-use assets obtained in exchange for operating lease liabilities	$	4.8	$	95.2
Non-cash financing activities:
Redemption of non-controlling interest	$	(4.0)	$	—

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

June 30, 2020

(Unaudited)

(1) General

In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries.

Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information.

a.Organization of Business

ENLC is a Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.” ENLC owns all of the common units of ENLK, a Delaware limited partnership formed in 2002. EnLink Midstream GP, LLC, a Delaware limited liability company and our wholly-owned subsidiary, is ENLK’s general partner. The General Partner manages ENLK’s operations and activities.

b.Nature of Business

We primarily focus on providing midstream energy services, including:

•gathering, compressing, treating, processing, transporting, storing, and selling natural gas;

•fractionating, transporting, storing, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines.

Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers.

Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets.

Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal.

c.Current Market Environment

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has now reached every region of the globe and has resulted in widespread adverse impacts on the global economy, on the energy industry as a whole and on midstream companies, and on our customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a reduction in global demand for condensate, natural gas, and NGLs and especially crude oil. While reductions in global demand for natural gas and NGLs were never as severe as for crude oil and the demand for crude oil has recovered from the steepest drops in April and May, global demand for energy is still reduced as of the date of this report from levels before the pandemic in mid-February. The decline in demand, coupled with the failure of OPEC+ to quickly agree on oil production cuts, resulted in a decline in the market price for these commodities, most severely for crude oil. Although OPEC+ agreed to production cuts in April, extended these cuts through July, and are expected to continue the production cuts beyond July, although at a more moderate level, and although United States oil producers have also curtailed their drilling programs, these cuts have not been enough to fully offset demand loss attributable to the COVID-19 pandemic and market prices remain lower than prior to the pandemic.

As a result of the supply/demand imbalance, reduced commodity prices, and an uncertain timeline for recovery, oil and natural gas producers, including many of our customers, have curtailed their current drilling and production activity, including in some cases by shutting-in production, as well as reducing their plans for future drilling and production activity. As a result of these decreases in producer activity, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems.

There is considerable uncertainty regarding how long COVID-19 will persist and affect economic conditions and the extent and duration of changes in consumer behavior, such as the reluctance to travel, as well as governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how significantly and how long they will continue to affect us. We expect to see continued volatility in crude oil, condensate, natural gas, and NGL prices for the foreseeable future, which may, over the long term, adversely impact our business. A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for oil, condensate natural gas and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders).

(2) Significant Accounting Policies

a.Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2019. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income (loss). All significant intercompany balances and transactions have been eliminated in consolidation.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

b.Revenue Recognition

Minimum Volume Commitments and Firm Transportation Contracts

Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue.

For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue.

The following table summarizes the contractually committed fees that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three and six months ended June 30, 2020, we had contractual commitments of $41.4 million and $83.2 million under our MVC contracts, respectively, and recorded $13.4 million and $25.2 million of revenue due to volume shortfalls, respectively.


MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)	$	126.9
2021	115.1
2022	99.8
2023	90.5
2024	77.0
Thereafter	143.3
Total	$	652.6

____________________________

(1)Amounts do not represent expected shortfall under these commitments.

c.Property and Equipment

Impairment Review. In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.

For the three months ended June 30, 2020, we recognized a $1.5 million impairment on property and equipment related to cancelled projects. For the six months ended June 30, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows, and a $1.9 million impairment related to certain cancelled projects.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

d.Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require us to purchase such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interests are not considered to be a component of members’ equity and are reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as a redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions). When the redemption feature is exercised the redemption value of the non-controlling interest is reclassified to a liability on the consolidated balance sheets.

During the first quarter of 2020, a non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated liability of $4.0 million related to the redemption of the non-controlling interest on the consolidated balance sheet as of June 30, 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder.

e.Adopted Accounting Standards

Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. For the three and six months ended June 30, 2020, we did not capitalize any cloud computing costs. However, to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statements of operations, rather than “Depreciation and amortization.”

Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(3) Goodwill and Intangible Assets

Goodwill

We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year cash flow multiples, and estimated future cash flows, including volume and price forecasts, capital expenditures, and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations.

Goodwill Impairment Analysis for the six months ended June 30, 2020

During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a quantitative goodwill impairment analysis on the remaining goodwill in the Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of $184.6 million was recognized as an impairment loss on the consolidated statement of operations for the six months ended June 30, 2020.

Goodwill Impairment Analysis for the six months ended June 30, 2019

During the first quarter of 2019, we recognized a $186.5 million goodwill impairment in our Louisiana reporting unit.

Intangible Assets

The following table represents our change in carrying value of intangible assets (in millions):


	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Six Months Ended June 30, 2020
Customer relationships, beginning of period	$	1,795.8	$	(545.9)	$	1,249.9
Amortization expense	—		(61.8)		(61.8)
Retirements (1)	(1.6)		0.6		(1.0)
Customer relationships, end of period	$	1,794.2	$	(607.1)	$	1,187.1

____________________________

(1)Intangible assets retired as a result of the disposition of certain non-core assets.

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from 10 to 20 years.

The weighted average amortization period is 15.0 years. Amortization expense was $30.9 million and $31.0 million for the three months ended June 30, 2020 and 2019, respectively, and $61.8 million and $61.9 million for the six months ended June 30, 2020 and 2019, respectively.

The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):


2020 (remaining)	$	61.7
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8

Total	$	1,187.1

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(4) Related Party Transactions

Transactions with Cedar Cove JV. For the three and six months ended June 30, 2020, we recorded cost of sales of $1.3 million and $4.2 million, respectively, and for the three and six months ended June 30, 2019, we recorded cost of sales of $5.8 million and $13.9 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at its Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $0.4 million and $1.1 million at June 30, 2020 and December 31, 2019, respectively.

Management believes the foregoing transactions with related parties were executed on terms that are fair and reasonable to us. The amounts related to related party transactions are included in the accompanying consolidated financial statements.

(5) Long-Term Debt

As of June 30, 2020 and December 31, 2019, long-term debt consisted of the following (in millions):


	June 30, 2020										December 31, 2019
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Consolidated Credit Facility due 2024 (1)	$	400.0	$	—	$	400.0	$	350.0	$	—	$	350.0
Term Loan due 2021 (2)	850.0		—		850.0		850.0		—		850.0
ENLK’s 4.40% Senior unsecured notes due 2024	521.8		1.2		523.0		550.0		1.5		551.5
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.6)		720.2		750.0		(0.7)		749.3
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.4)		490.6		500.0		(0.5)		499.5
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		500.0		—		500.0
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.8)		444.2		450.0		(5.9)		444.1
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term, including current maturities of long-term debt	$	4,782.3	$	(5.9)	4,776.4		$	4,800.0	$	(5.9)	4,794.1
Debt issuance cost (3)					(27.4)						(29.8)
Long-term debt, net of unamortized issuance cost					$	4,749.0					$	4,764.3

____________________________

(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.8% and 3.3% at June 30, 2020 and December 31, 2019, respectively.

(2)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.7% and 3.2% at June 30, 2020 and December 31, 2019, respectively.

(3)Net of amortization of $12.6 million and $10.9 million at June 30, 2020 and December 31, 2019, respectively.

Consolidated Credit Facility

The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($400.0 million as of June 30, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($23.0 million as of June 30, 2020). The obligations under the Consolidated Credit Facility are unsecured.

The Consolidated Credit Facility includes provisions for additional financial institutions to become lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $2.25 billion for all commitments under the Consolidated Credit Facility.

The Consolidated Credit Facility will mature on January 25, 2024, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Consolidated Credit Facility contains certain financial, operational, and legal covenants.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Consolidated Credit Facility, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Consolidated Credit Facility) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.

Borrowings under the Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately.

At June 30, 2020, we were in compliance with and expect to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months.

Term Loan

On December 11, 2018, ENLK entered into the Term Loan with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan and the outstanding balance becomes due, ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. The outstanding balance of the Term Loan was $850.0 million as of June 30, 2020. The obligations under the Term Loan are unsecured.

The Term Loan will mature on December 10, 2021. The Term Loan contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Term Loan, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Term Loan) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.

Borrowings under the Term Loan bear interest at ENLC’s option at LIBOR plus an applicable margin (ranging from 1.0% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.5%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately.

At June 30, 2020, we were in compliance with and expect to be in compliance with the financial covenants of the Term Loan for at least the next twelve months.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Senior Unsecured Notes Repurchases

For the three and six months ended June 30, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions):


	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
Debt repurchased	$	57.2	$	67.7
Aggregate payments	(30.8)		(36.0)
Net discount on repurchased debt	(0.3)		(0.3)
Accrued interest on repurchased debt	0.6		0.6
Gain on extinguishment of debt	$	26.7	$	32.0

(6) Income Taxes

The components of our income tax benefit (expense) are as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Current income tax expense	$	(0.4)	$	(0.3)	$	(0.7)	$	(1.3)
Deferred income tax benefit (expense)	(11.3)		5.7		22.7		4.9
Income tax benefit (expense)	$	(11.7)	$	5.4	$	22.0	$	3.6

The following schedule reconciles total income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to income (loss) before income taxes (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Expected income tax benefit (expense) based on federal statutory rate	$	(3.7)	$	4.5	$	63.6	$	41.2
State income tax benefit (expense), net of federal benefit	(1.0)		0.4		7.0		4.3
Unit-based compensation (1)	(6.8)		(0.1)		(4.4)		—
Non-deductible expense related to goodwill impairment	—		—		(43.4)		(43.8)
Other	(0.2)		0.6		(0.8)		1.9
Income tax benefit (expense)	$	(11.7)	$	5.4	$	22.0	$	3.6

____________________________

(1)Related to book-to-tax differences recorded upon the vesting of restricted incentive units.

Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The deferred tax assets, net of deferred tax liabilities, are included in “Other assets, net” in the consolidated balance sheets. As of June 30, 2020, we had $58.3 million of deferred tax assets, net of $407.3 million of deferred tax liabilities. As of December 31, 2019, we had $32.2 million of deferred tax assets, net of $354.0 million of deferred tax liabilities.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of June 30, 2020 and December 31, 2019, there were 59,897,920 and 59,599,550 Series B Preferred Units issued and outstanding, respectively.

A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2020 and 2019 is provided below:


Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2020
Fourth Quarter of 2019	148,999	$	16.8	February 13, 2020
First Quarter of 2020	149,371	$	16.8	May 13, 2020
Second Quarter of 2020	149,745	$	16.8	August 13, 2020


2019
Fourth Quarter of 2018	425,785	$	16.5	February 13, 2019
First Quarter of 2019	147,887	$	16.7	May 14, 2019
Second Quarter of 2019	148,257	$	17.1	August 13, 2019

b.Series C Preferred Units

As of June 30, 2020 and December 31, 2019, there were 400,000 Series C Preferred Units issued and outstanding. ENLK distributed $12.0 million to holders of Series C Preferred Units during the three and six months ended June 30, 2020 and 2019, respectively.

c.ENLK Common Unit Distributions

On February 13, 2019, ENLK paid $0.39 per ENLK common unit related to the fourth quarter of 2018.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(8) Members’ Equity

a.Earnings Per Unit and Dilution Computations

As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Distributed earnings allocated to:
Common units (1)	$	45.9	$	137.8	$	91.7	$	247.2
Unvested restricted units (1)	0.8		1.8		1.6		3.0
Total distributed earnings	$	46.7	$	139.6	$	93.3	$	250.2
Undistributed loss allocated to:
Common units	$	(42.2)	$	(153.5)	$	(369.6)	$	(437.3)
Unvested restricted units	(0.4)		(2.2)		(6.4)		(5.3)
Total undistributed loss	$	(42.6)	$	(155.7)	$	(376.0)	$	(442.6)
Net income (loss) allocated to:
Common units	$	3.7	$	(15.7)	$	(277.9)	$	(190.1)
Unvested restricted units	0.4		(0.4)		(4.8)		(2.3)
Total net income (loss)	$	4.1	$	(16.1)	$	(282.7)	$	(192.4)
Basic and diluted net income (loss) per unit:
Basic	$	0.01	$	(0.03)	$	(0.58)	$	(0.44)
Diluted	$	0.01	$	(0.03)	$	(0.58)	$	(0.44)

____________________________

(1)For the three months ended June 30, 2020 and 2019, distributed earnings represent a declared distribution of $0.09375 per unit payable on August 13, 2020 and a distribution of $0.283 per unit paid on August 13, 2019, respectively.

(2)For the six months ended June 30, 2020, distributed earnings included a distribution of $0.09375 per unit paid on May 13, 2020 and a declared distribution of $0.09375 per unit payable on August 13, 2020. For the six months ended June 30, 2019, distributed earnings included distributions of $0.279 per unit paid on May 14, 2019 and $0.283 per unit paid on August 13, 2019.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	489.3	487.2	489.0	439.9

Diluted weighted average units outstanding:
Weighted average basic common units outstanding	489.3	487.2	489.0	439.9
Dilutive effect of non-vested restricted units (1)	1.1	—	—	—

Total weighted average diluted common units outstanding	490.4	487.2	489.0	439.9

____________________________

(1)All common unit equivalents were antidilutive for the six months ended June 30, 2020 and for the three and six months ended June 30, 2019 since a net loss existed for those periods.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

b.Distributions

A summary of our distribution activity relating to the ENLC common units for the six months ended June 30, 2020 and 2019, respectively, is provided below:


Declaration period	Distribution/unit		Date paid/payable
2020
Fourth Quarter of 2019	$	0.1875	February 13, 2020
First Quarter of 2020	$	0.09375	May 13, 2020
Second Quarter of 2020	$	0.09375	August 13, 2020


2019
Fourth Quarter of 2018	$	0.275	February 14, 2019
First Quarter of 2019	$	0.279	May 14, 2019
Second Quarter of 2019	$	0.283	August 13, 2019

(9) Investment in Unconsolidated Affiliates

As of June 30, 2020, our unconsolidated investments consisted of a 38.75% ownership in GCF and a 30% ownership in the Cedar Cove JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
GCF

Distributions	$	—	$	7.4	$	1.6	$	9.6
Equity in income	$	0.3	$	5.2	$	2.1	$	10.9

Cedar Cove JV

Distributions	$	0.2	$	0.2	$	0.4	$	0.5
Equity in loss	$	(1.0)	$	(0.5)	$	(1.1)	$	(0.9)

Total

Distributions	$	0.2	$	7.6	$	2.0	$	10.1
Equity in income (loss)	$	(0.7)	$	4.7	$	1.0	$	10.0

The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2020 and December 31, 2019 (in millions):


	June 30, 2020		December 31, 2019
GCF	$	39.7	$	39.2
Cedar Cove JV	2.4		3.9
Total investment in unconsolidated affiliates	$	42.1	$	43.1

(10) Employee Incentive Plans

a.Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.

Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Cost of unit-based compensation charged to operating expense	$	2.0	$	2.1	$	4.2	$	2.4
Cost of unit-based compensation charged to general and administrative expense	5.4		5.9		12.0		16.7
Total unit-based compensation expense	$	7.4	$	8.0	$	16.2	$	19.1
Non-controlling interest in unit-based compensation	$	—	$	—	$	—	$	0.5
Amount of related income tax benefit recognized in net income (loss) (1)	$	1.7	$	1.9	$	3.8	$	4.4

____________________________

(1)For the three and six months ended June 30, 2020, the amount of related income tax expense recognized in net income (loss) excluded $6.8 million and $4.4 million, respectively, related to book-to-tax differences recorded upon vesting of restricted units. For the three months ended June 30, 2019, the amount of related income tax expense recognized in net income excluded $0.1 million related to book-to-tax differences recorded upon vesting of restricted units. There was no income tax expense or benefit related to book-to-tax differences recorded upon vesting of restricted units for the six months ended June 30, 2020.

b.ENLC Restricted Incentive Units

ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2020 is provided below:


	Six Months Ended June 30, 2020
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	4,063,605		$	13.85
Granted (1)	4,673,848		5.55
Vested (1)(2)	(2,413,687)		10.35
Forfeited	(478,304)		8.39
Non-vested, end of period	5,845,462		$	9.11
Aggregate intrinsic value, end of period (in millions)	$	14.3

____________________________

(1)Restricted incentive units typically vest at the end of three years. In February 2020, ENLC granted 1,144,842 restricted incentive units with a fair value of $5.2 million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included 851,940 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2020 and 2019 is provided below (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
ENLC Restricted Incentive Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	0.8	$	0.5	$	10.9	$	12.9
Fair value of units vested	$	6.1	$	0.5	$	25.0	$	13.1

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(Unaudited)

As of June 30, 2020, there was $29.4 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. This cost is expected to be recognized over a weighted-average period of 1.8 years.

c.ENLC Performance Units

ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period.

The following table presents a summary of the performance units:


	Six Months Ended June 30, 2020
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,317,856		$	14.22
Granted	1,161,986		7.32
Vested (1)	(178,403)		30.56
Forfeited	(37,646)		11.81
Non-vested, end of period	2,263,793		$	9.43
Aggregate intrinsic value, end of period (in millions)	$	5.5

____________________________

(1)Vested units included 67,775 units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2020 and 2019 is provided below (in millions).


	Three Months Ended June 30,						Six Months Ended June 30,
ENLC Performance Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	—	$	—	$	0.9	$	1.8
Fair value of units vested	$	0.5	$	—	$	5.5	$	1.9

As of June 30, 2020, there was $14.5 million of unrecognized compensation cost that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 1.7 years.

The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:


ENLC Performance Units:	January 2020			March 2020
Grant-Date Fair Value	$	7.69		$	1.13
Beginning TSR price	$	6.13		$	1.25
Risk-free interest rate	1.62		%	0.42		%
Volatility factor	37.00		%	51.00		%

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(Unaudited)

d.ENLK Restricted Incentive Units

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.


	Six Months Ended June 30,
ENLK Restricted Incentive Units:	2019
Aggregate intrinsic value of units vested	$	8.0
Fair value of units vested	$	7.2

e.ENLK Performance Units

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.


	Six Months Ended June 30,
ENLK Performance Units:	2019
Aggregate intrinsic value of units vested	$	2.1
Fair value of units vested	$	1.7

(11) Derivatives

Interest Rate Swaps

In April 2019, we entered into an $850.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we pay a fixed interest rate of 2.28% in exchange for LIBOR-based variable interest through December 2021. There was no ineffectiveness related to this hedge.

The components of the gain (loss) on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Change in fair value of interest rate swap	$	2.0	$	(13.5)	$	(15.1)	$	(13.5)
Tax benefit (expense)	(0.5)		3.6		3.5		3.6
Gain (loss) on designated cash flow hedge	$	1.5	$	(9.9)	$	(11.6)	$	(9.9)

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps, included in our consolidated income statement were as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Interest expense (income)	$	3.7	$	(0.3)	$	5.0	$	(0.3)

We expect to recognize an additional $18.4 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions):


	June 30, 2020		December 31, 2019


Fair value of derivative liabilities—current	$	(18.3)	$	(5.6)
Fair value of derivative liabilities—long-term	(9.3)		(6.8)
Net fair value of interest rate swaps	$	(27.6)	$	(12.4)

Commodity Swaps

The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Change in fair value of derivatives	$	(18.8)	$	7.2	$	(5.8)	$	5.2
Realized gain (loss) on derivatives	(3.6)		(0.3)		2.6		3.5
Gain (loss) on derivative activity	$	(22.4)	$	6.9	$	(3.2)	$	8.7

The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):


	June 30, 2020		December 31, 2019
Fair value of derivative assets—current	$	9.9	$	12.9
Fair value of derivative assets—long-term	5.8		4.3
Fair value of derivative liabilities—current	(13.0)		(8.8)
Fair value of derivative liabilities—long-term	(0.1)		—
Net fair value of commodity swaps	$	2.6	$	8.4

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at June 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022.

June 30, 2020

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(172.5)

(5.7)

NGL (long contracts)

Swaps

Gallons

3.4

(0.1)

Natural gas (short contracts)

Swaps

MMBtu

(21.6)

(0.2)

Natural gas (long contracts)

Swaps

MMBtu

15.9

(0.6)

Crude and condensate (short contracts)

Swaps

MMbbls

(10.7)

7.2

Crude and condensate (long contracts)

Swaps

MMbbls

0.6

2.0

Total fair value of commodity swaps

2.6

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of $15.7 million as of June 30, 2020 would be reduced to $8.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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(Unaudited)

(12) Fair Value Measurements

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):


	Level 2
	June 30, 2020		December 31, 2019
Interest rate swaps (1)	$	(27.6)	$	(12.4)
Commodity swaps (2)	$	2.6	$	8.4

____________________________

(1)The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates.

(2)The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.

Fair Value of Financial Instruments

The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):


	June 30, 2020						December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,749.0	$	3,791.1	$	4,764.3	$	4,444.2

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance costs of $27.4 million and $29.8 million as of June 30, 2020 and December 31, 2019, respectively. The respective fair values do not factor in debt issuance costs.

The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

The fair values of all senior unsecured notes as of June 30, 2020 and December 31, 2019 were based on Level 2 inputs from third-party market quotations.

(13) Segment Information

Identification of the majority of our operating segments is based principally upon geographic regions served:

•Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas;

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas;

•Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas;

•Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana and our crude oil operations in ORV; and

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, our derivative activity, and our general corporate assets and expenses.

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(Unaudited)

We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions):


	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Three Months Ended June 30, 2020
Natural gas sales	$	32.4	$	14.6	$	28.8	$	68.6	$	—	$	144.4
NGL sales	(0.1)		—		0.5		280.9		—		281.3
Crude oil and condensate sales	87.0		—		5.0		14.9		—		106.9

Product sales	119.3		14.6		34.3		364.4		—		532.6

NGL sales—related parties	59.5		13.9		56.0		3.2		(132.5)		0.1
Crude oil and condensate sales—related parties	—		0.4		0.1		—		(0.6)		(0.1)
Product sales—related parties	59.5		14.3		56.1		3.2		(133.1)		—
Gathering and transportation	13.1		44.2		52.5		11.5		—		121.3
Processing	7.5		33.0		32.1		0.6		—		73.2
NGL services	—		0.1		—		18.6		—		18.7
Crude services	5.0		—		4.6		11.0		—		20.6
Other services	0.2		0.2		0.1		0.4		—		0.9
Midstream services	25.8		77.5		89.3		42.1		—		234.7



Crude services—related parties	—		—		0.1		—		(0.1)		—

Midstream services—related parties	—		—		0.1		—		(0.1)		—
Revenue from contracts with customers	204.6		106.4		179.8		409.7		(133.2)		767.3
Cost of sales	(138.4)		(18.9)		(61.1)		(312.5)		133.2		(397.7)
Operating expenses	(22.7)		(18.5)		(19.4)		(27.5)		—		(88.1)
Loss on derivative activity	—		—		—		—		(22.4)		(22.4)
Segment profit (loss)	$	43.5	$	69.0	$	99.3	$	69.7	$	(22.4)	$	259.1
Depreciation and amortization	$	(31.0)	$	(36.4)	$	(54.1)	$	(34.6)	$	(2.1)	$	(158.2)
Impairments	$	—	$	—	$	—	$	(1.5)	$	—	$	(1.5)

Capital expenditures	$	46.9	$	3.0	$	3.0	$	15.6	$	0.7	$	69.2

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Three Months Ended June 30, 2019
Natural gas sales	$	(1.0)	$	31.9	$	60.3	$	102.6	$	—	$	193.8
NGL sales	0.8		8.7		4.3		498.8		—		512.6
Crude oil and condensate sales	632.0		—		28.6		83.5		—		744.1
Other	—		—		(0.1)		—		—		(0.1)
Product sales	631.8		40.6		93.1		684.9		—		1,450.4
Natural gas sales—related parties	0.4		0.3		—		—		(0.7)		—
NGL sales—related parties	76.4		22.2		104.6		5.3		(208.5)		—
Crude oil and condensate sales—related parties	6.9		1.7		—		—		(8.6)		—
Product sales—related parties	83.7		24.2		104.6		5.3		(217.8)		—
Gathering and transportation	11.3		49.0		59.2		16.7		—		136.2
Processing	7.3		35.7		35.7		0.8		—		79.5
NGL services	—		—		—		10.0		—		10.0
Crude services	5.3		—		5.2		12.9		—		23.4
Other services	2.9		0.3		0.2		0.2		—		3.6
Midstream services	26.8		85.0		100.3		40.6		—		252.7


NGL services—related parties	—		—		—		(0.3)		0.3		—
Crude services—related parties	—		—		1.2		—		(1.2)		—

Midstream services—related parties	—		—		1.2		(0.3)		(0.9)		—
Revenue from contracts with customers	742.3		149.8		299.2		730.5		(218.7)		1,703.1
Cost of sales	(680.5)		(51.0)		(159.4)		(627.9)		218.7		(1,300.1)
Operating expenses	(28.4)		(25.8)		(26.1)		(37.6)		—		(117.9)
Gain on derivative activity	—		—		—		—		6.9		6.9
Segment profit	$	33.4	$	73.0	$	113.7	$	65.0	$	6.9	$	292.0
Depreciation and amortization	$	(30.1)	$	(36.9)	$	(47.6)	$	(36.9)	$	(2.2)	$	(153.7)

Goodwill	$	184.6	$	125.7	$	813.4	$	—	$	—	$	1,123.7
Capital expenditures	$	52.4	$	27.0	$	70.3	$	19.5	$	2.4	$	171.6

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Six Months Ended June 30, 2020
Natural gas sales	$	47.5	$	34.7	$	69.9	$	150.2	$	—	$	302.3
NGL sales	0.1		0.3		1.7		654.6		—		656.7
Crude oil and condensate sales	372.0		—		21.2		73.3		—		466.5

Product sales	419.6		35.0		92.8		878.1		—		1,425.5

NGL sales—related parties	105.4		31.1		123.6		10.0		(270.1)		—
Crude oil and condensate sales—related parties	0.1		1.9		(0.1)		—		(1.9)		—
Product sales—related parties	105.5		33.0		123.5		10.0		(272.0)		—
Gathering and transportation	29.4		90.1		108.8		23.2		—		251.5
Processing	11.8		68.4		65.4		1.3		—		146.9
NGL services	—		0.1		—		38.2		—		38.3
Crude services	9.2		—		8.9		21.6		—		39.7
Other services	0.8		0.5		0.2		0.8		—		2.3
Midstream services	51.2		159.1		183.3		85.1		—		478.7



Crude services—related parties	—		—		0.2		—		(0.2)		—

Midstream services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	576.3		227.1		399.8		973.2		(272.2)		1,904.2
Cost of sales	(452.3)		(45.9)		(154.8)		(772.2)		272.2		(1,153.0)
Operating expenses	(48.2)		(39.0)		(42.3)		(59.3)		—		(188.8)
Loss on derivative activity	—		—		—		—		(3.2)		(3.2)
Segment profit (loss)	$	75.8	$	142.2	$	202.7	$	141.7	$	(3.2)	$	559.2
Depreciation and amortization	$	(60.2)	$	(73.6)	$	(110.7)	$	(72.4)	$	(4.1)	$	(321.0)
Impairments	$	(184.6)	$	—	$	—	$	(169.9)	$	—	$	(354.5)

Capital expenditures	$	132.9	$	7.7	$	11.5	$	30.8	$	1.1	$	184.0

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Six Months Ended June 30, 2019
Natural gas sales	$	35.1	$	82.5	$	121.9	$	224.8	$	—	$	464.3
NGL sales	0.6		18.0		13.2		1,071.9		—		1,103.7
Crude oil and condensate sales	1,212.8		—		58.2		142.3		—		1,413.3

Product sales	1,248.5		100.5		193.3		1,439.0		—		2,981.3
Natural gas sales—related parties	0.4		0.3		—		—		(0.7)		—
NGL sales—related parties	173.6		50.7		230.7		8.5		(463.5)		—
Crude oil and condensate sales—related parties	10.9		2.7		—		—		(13.6)		—
Product sales—related parties	184.9		53.7		230.7		8.5		(477.8)		—
Gathering and transportation	21.6		112.6		114.5		33.9		—		282.6
Processing	15.0		56.8		69.8		1.7		—		143.3
NGL services	—		—		—		21.7		—		21.7
Crude services	10.5		—		9.2		26.7		—		46.4
Other services	4.4		0.5		(0.1)		0.4		—		5.2
Midstream services	51.5		169.9		193.4		84.4		—		499.2


NGL services—related parties	—		—		—		(3.3)		3.3		—
Crude services—related parties	—		—		1.5		—		(1.5)		—

Midstream services—related parties	—		—		1.5		(3.3)		1.8		—
Revenue from contracts with customers	1,484.9		324.1		618.9		1,528.6		(476.0)		3,480.5
Cost of sales	(1,356.7)		(124.7)		(343.6)		(1,314.5)		476.0		(2,663.5)
Operating expenses	(56.2)		(51.5)		(51.5)		(73.2)		—		(232.4)
Gain on derivative activity	—		—		—		—		8.7		8.7
Segment profit	$	72.0	$	147.9	$	223.8	$	140.9	$	8.7	$	593.3
Depreciation and amortization	$	(58.0)	$	(71.2)	$	(93.7)	$	(78.7)	$	(4.2)	$	(305.8)
Impairments	$	—	$	—	$	—	$	(186.5)	$	—	$	(186.5)
Goodwill	$	184.6	$	125.7	$	813.4	$	—	$	—	$	1,123.7
Capital expenditures	$	148.3	$	31.3	$	178.5	$	60.5	$	4.0	$	422.6

The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Segment profit	$	259.1	$	292.0	$	559.2	$	593.3
General and administrative expenses	(23.5)		(32.2)		(53.9)		(83.6)
Loss on disposition of assets	(5.2)		(0.1)		(4.6)		(0.1)
Depreciation and amortization	(158.2)		(153.7)		(321.0)		(305.8)
Impairments	(1.5)		—		(354.5)		(186.5)
Loss on secured term loan receivable	—		(52.9)		—		(52.9)

Operating income (loss)	$	70.7	$	53.1	$	(174.8)	$	(35.6)

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as of June 30, 2020 and December 31, 2019 (in millions):


Segment Identifiable Assets:	June 30, 2020		December 31, 2019
Permian	$	2,268.5	$	2,465.7
North Texas	1,061.7		1,135.8
Oklahoma	2,934.4		3,035.0
Louisiana	2,273.7		2,562.0
Corporate	180.5		137.3
Total identifiable assets	$	8,718.8	$	9,335.8

(14) Other Information

The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):


Other current assets:	June 30, 2020		December 31, 2019
Natural gas and NGLs inventory	$	39.7	$	43.4
Prepaid expenses and other	18.9		14.4
Other current assets	$	58.6	$	57.8


Other current liabilities:	June 30, 2020		December 31, 2019
Accrued interest	$	35.4	$	37.1
Accrued wages and benefits, including taxes	15.8		31.5
Accrued ad valorem taxes	23.0		28.5
Capital expenditure accruals	20.6		42.4
Retention liability	11.0		8.7
Short-term lease liability	16.0		21.1
Suspense producer payments	12.1		13.8
Operating expense accruals	9.2		10.8
Other	17.1		12.3
Other current liabilities	$	160.2	$	206.2

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

Please read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. In addition, please refer to the Definitions page set forth in this report prior to Part I—Financial Information.

Overview

ENLC is a Delaware limited liability company formed in October 2013. ENLC’s assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. All of our midstream energy assets are owned and operated by ENLK and its subsidiaries. We primarily focus on providing midstream energy services, including:

•gathering, compressing, treating, processing, transporting, storing, and selling natural gas;

•fractionating, transporting, storing, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

Our midstream energy asset network includes approximately 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately 290,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography. We have five reportable segments:

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas;

We manage our operations by focusing on gross operating margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. We define gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 94% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the six months ended June 30, 2020. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

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The following customers individually represented greater than 10% of our consolidated revenues. These customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results of operations because the revenues and gross operating margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues.


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Devon	17.7	%	(1)		15.0	%	(1)
Dow Hydrocarbons and Resources LLC	13.5	%	10.1	%	12.3	%	10.4	%
Marathon Petroleum Corporation	10.3	%	15.2	%	14.8	%	14.7	%

____________________________

(1)Consolidated revenues for Devon did not exceed 10% of our consolidated revenues for the three and six months ended June 30, 2019.

Our revenues and gross operating margins are generated from eight primary sources:

•gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own;

•processing natural gas at our processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services;

•providing brine disposal services; and

•providing natural gas, crude oil, and NGL storage.

We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher gross operating margins from product upgrades during periods with higher NGL prices.

We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction.

We realize gross operating margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee component contracts, or a combination of these contractual arrangements. “See Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a detailed description of these contractual arrangements. Under any of these gathering and

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processing arrangements, we may earn a fee for the services performed, or we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize a net margin as our fee. Under margin contract arrangements, our gross operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our gross operating margins are driven by throughput volume.

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate moved through or by our assets.

Recent Developments Affecting Industry Conditions and Our Business

Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. We have implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a cross-functional COVID-19 response team to address various impacts of the situation, as they have been developing. We also have modified certain business practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employees who can execute their work remotely, and encouraging employees to adhere to local and regional social distancing recommendations) to support efforts to reduce the spread of COVID-19 and to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. We also have promoted heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and operations. We continue to evaluate and adjust these preventative measures, response plans and business practices with the evolving impacts of COVID-19.

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As of the date of this report, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded results. Our systems, pipelines, and facilities have remained operational. We have also moved quickly and decisively, and we continue to adapt and respond promptly, to implement strategies to reduce costs, increase operational efficiencies, and lower our capital spending. As we previously announced, we intend to reduce our capital expenditures in 2020, including both growth and maintenance capital expenditures, to between $190 million and $250 million, a 65% reduction from 2019 total capital spending. We have also reduced costs across our platform and we intend to reduce our general and administrative and operational expenses by $120 million for the full-year 2020 versus the twelve months ended December 31, 2019. Also, as of June 30, 2020, we had approximately $52 million of cash on our balance sheet and have drawn only approximately $400 million on the $1.75 billion Consolidated Credit Facility. We have not requested any funding under any federal or other governmental programs to support our operations, and we do not expect to utilize any such funding. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented.

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to unitholders) at this time due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the outbreak, the effect of the outbreak on economic, social and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, the development and timing of effective treatments and vaccines, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic, social and operating conditions resume.

For additional discussion regarding risks associated with the COVID-19 pandemic, see Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

Other Recent Developments

Riptide Processing Plant. In March 2020, we completed construction of a 55 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 220 MMcf/d.

Delaware Basin Processing Plant. In August 2019, we commenced construction of our Tiger Plant, which will expand our Delaware Basin processing capacity by an additional 200 MMcf/d. We expect the plant to be operational in the third quarter of 2020. This processing plant is owned by the Delaware Basin JV.

Non-GAAP Financial Measures

To assist management in assessing our business, we use the following non-GAAP financial measures: Adjusted earnings before interest, taxes, and depreciation and amortization (“adjusted EBITDA”), distributable cash flow available to common unitholders (“distributable cash flow”), excess free cash flow, and gross operating margin.

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; loss on secured term loan receivable, (income) loss from unconsolidated affiliates; distributions from unconsolidated affiliates; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; (payments under onerous performance obligation); transaction costs; accretion expense associated with asset retirement obligations; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is a primary metric used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:

•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

•the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders;

•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and

•the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, net of interest income; income tax expense (benefit); and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

The following table reconciles adjusted EBITDA to net income (loss) (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Net income (loss)	$	29.8	$	9.1	$	(230.6)	$	(125.7)
Interest expense, net of interest income	55.2		54.3		110.8		103.9
Depreciation and amortization	158.2		153.7		321.0		305.8
Impairments	1.5		—		354.5		186.5
Loss on secured term loan receivable (1)	—		52.9		—		52.9
(Income) loss from unconsolidated affiliates	0.7		(4.7)		(1.0)		(10.0)
Distributions from unconsolidated affiliates	0.2		7.6		2.0		10.1
Loss on disposition of assets	5.2		0.1		4.6		0.1
Gain on extinguishment of debt	(26.7)		—		(32.0)		—
Unit-based compensation	7.4		8.0		16.2		19.1
Income tax expense (benefit)	11.7		(5.4)		(22.0)		(3.6)
Unrealized (gain) loss on commodity swaps	18.8		(7.2)		5.8		(5.2)
Payments under onerous performance obligation offset to other current and long-term liabilities	—		(4.5)		—		(9.0)
Transaction costs (2)	—		0.4		—		13.9
Other (3)	(0.4)		0.1		(0.5)		0.4
Adjusted EBITDA before non-controlling interest	261.6		264.4		528.8		539.2
Non-controlling interest share of adjusted EBITDA from joint ventures (4)	(6.5)		(5.2)		(13.7)		(11.8)
Adjusted EBITDA, net to ENLC	$	255.1	$	259.2	$	515.1	$	527.4

____________________________

(1)In May 2018, we restructured our natural gas gathering and processing contract with White Star, and, as a result, recognized the discounted present value of a secured term loan receivable granted to us by White Star. We recorded a $52.9 million loss in our consolidated statement of operations for the three and six months ended June 30, 2019 related to the write-off of the secured term loan receivable.

(2)Represents transaction costs attributable to costs incurred related to the Merger in January 2019.

(3)Includes accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(4)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.

Distributable Cash Flow and Excess Free Cash Flow

We define distributable cash flow as adjusted EBITDA, net to ENLC, less interest expense, net of interest income; maintenance capital expenditures, excluding maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities; accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid; non-cash interest income; and current income taxes. Excess free cash flow

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is defined as distributable cash flow less distributions declared on common units and growth capital expenditures, excluding growth capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated joint ventures.

Distributable cash flow and excess free cash flow are used as supplemental liquidity measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions, and make capital expenditures.

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations.

Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income.

The GAAP measure most directly comparable to distributable cash flow and excess free cash flow is net cash provided by operating activities. Distributable cash flow and excess free cash flow should not be considered alternatives to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Distributable cash flow and excess free cash flow have important limitations because they exclude some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Distributable cash flow and excess free cash flow may not be comparable to similarly titled measures of other companies because other companies may not calculate these non-GAAP metrics in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as distributable cash flow and excess free cash flow, to evaluate our overall liquidity.

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The following table reconciles excess free cash flow, distributable cash flow, and adjusted EBITDA to net cash provided by operating activities (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Net cash provided by operating activities	$	134.8	$	257.5	$	316.8	$	521.5
Interest expense (1)	54.0		53.9		108.7		103.4
Current income tax expense	0.4		0.3		0.7		1.3
Transaction costs (2)	—		0.4		—		13.9
Other (3)	(5.1)		1.6		0.5		0.1
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	50.2		(165.9)		(119.1)		(263.3)
Accounts payable, accrued product purchases, and other accrued liabilities (4)	27.3		116.6		221.2		162.3
Adjusted EBITDA before non-controlling interest	261.6		264.4		528.8		539.2
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(6.5)		(5.2)		(13.7)		(11.8)
Adjusted EBITDA, net to ENLC	255.1		259.2		515.1		527.4
Interest expense, net of interest income	(55.2)		(54.3)		(110.8)		(103.9)
Maintenance capital expenditures, net to ENLC (6)	(7.7)		(13.2)		(15.9)		(21.7)
ENLK preferred unit accrued cash distributions (7)	(22.8)		(23.1)		(45.6)		(45.8)
Other (8)	(0.3)		(1.0)		(0.6)		(3.5)
Distributable cash flow	169.1		167.6		342.2		352.5
Common distributions declared	(46.4)		(139.3)		(92.9)		(276.6)
Growth capital expenditures, net to ENLC (6)	(50.7)		(141.9)		(133.3)		(361.5)
Excess free cash flow	$	72.0	$	(113.6)	$	116.0	$	(285.6)

____________________________

(1)Net of amortization of debt issuance costs and discount and premium, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA.

(2)Represents transaction costs attributable to costs incurred related to the Merger in January 2019.

(3)Includes accruals for settled commodity swap transactions, distributions received from equity method investments to the extent those distributions exceed earnings from the investment, and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(4)Net of payments under onerous performance obligation offset to other current and long-term liabilities during the three and six months ended June 30, 2019.

(5)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.

(6)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.

(7)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See “Item 1. Financial Statements— Note 7” for information on the cash distributions earned by holders of the Series B Preferred Units and Series C Preferred Units. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.

(8)Includes non-cash interest income and current income tax expense.

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Gross Operating Margin

We define gross operating margin as revenues less cost of sales. We present gross operating margin by segment in “Results of Operations.” We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to gross operating margin is operating income (loss). Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) as determined in accordance with GAAP. Gross operating margin has important limitations because it excludes all operating costs that affect operating income (loss) except cost of sales. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

The following table provides a reconciliation of operating income (loss) to gross operating margin (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Operating income (loss)	$	70.7	$	53.1	$	(174.8)	$	(35.6)

Add:
Operating expenses	88.1		117.9		188.8		232.4
General and administrative expenses	23.5		32.2		53.9		83.6
Loss on disposition of assets	5.2		0.1		4.6		0.1
Depreciation and amortization	158.2		153.7		321.0		305.8
Impairments	1.5		—		354.5		186.5
Loss on secured term loan receivable	—		52.9		—		52.9
Gross operating margin	$	347.2	$	409.9	$	748.0	$	825.7

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Results of Operations

The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin, which we define as revenue less cost of sales as reflected in the table below (in millions, except volumes):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Permian Segment
Revenues	$	204.6	$	742.3	$	576.3	$	1,484.9
Cost of sales	(138.4)		(680.5)		(452.3)		(1,356.7)
Total gross operating margin	$	66.2	$	61.8	$	124.0	$	128.2
North Texas Segment
Revenues	$	106.4	$	149.8	$	227.1	$	324.1
Cost of sales	(18.9)		(51.0)		(45.9)		(124.7)
Total gross operating margin	$	87.5	$	98.8	$	181.2	$	199.4
Oklahoma Segment
Revenues	$	179.8	$	299.2	$	399.8	$	618.9
Cost of sales	(61.1)		(159.4)		(154.8)		(343.6)
Total gross operating margin	$	118.7	$	139.8	$	245.0	$	275.3
Louisiana Segment
Revenues	$	409.7	$	730.5	$	973.2	$	1,528.6
Cost of sales	(312.5)		(627.9)		(772.2)		(1,314.5)
Total gross operating margin	$	97.2	$	102.6	$	201.0	$	214.1
Corporate Segment
Revenues	$	(155.6)	$	(211.8)	$	(275.4)	$	(467.3)
Cost of sales	133.2		218.7		272.2		476.0
Total gross operating margin	$	(22.4)	$	6.9	$	(3.2)	$	8.7
Total
Revenues	$	744.9	$	1,710.0	$	1,901.0	$	3,489.2
Cost of sales	(397.7)		(1,300.1)		(1,153.0)		(2,663.5)
Total gross operating margin	$	347.2	$	409.9	$	748.0	$	825.7

Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d)	871,500		676,000		851,300		666,800
Processing (MMBtu/d)	896,100		724,100		878,900		718,100
Crude Oil Handling (Bbls/d)	112,300		145,100		122,900		146,200
North Texas Segment
Gathering and Transportation (MMBtu/d)	1,485,900		1,646,900		1,531,800		1,664,900
Processing (MMBtu/d)	670,600		770,100		685,200		750,100
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	1,092,600		1,314,900		1,156,800		1,279,800
Processing (MMBtu/d)	1,082,100		1,298,800		1,118,300		1,265,400
Crude Oil Handling (Bbls/d)	30,000		53,800		33,300		41,600
Louisiana Segment
Gathering and Transportation (MMBtu/d)	1,873,600		1,925,900		1,958,400		1,997,800
Processing (MMBtu/d)	197,200		337,100		183,400		402,200
Crude Oil Handling (Bbls/d)	15,700		20,000		16,600		17,500
NGL Fractionation (Gals/d)	7,344,800		7,477,400		7,764,500		7,227,000
Brine Disposal (Bbls/d)	1,400		3,400		1,600		3,400

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Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019

Gross Operating Margin. Gross operating margin was $347.2 million for the three months ended June 30, 2020 compared to $409.9 million for the three months ended June 30, 2019, a decrease of $62.7 million, or 15.3%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment increased $4.4 million, resulting from (i) a $2.5 million increase in gross operating margin from our Permian crude assets primarily attributable to volume growth in our Delaware Basin assets, which was partially offset by the expiration of an MVC related to our South Texas assets in July 2019, and (ii) a $1.9 million increase in gross operating margin from our Permian gas assets primarily attributable to volume growth.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $11.3 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $21.1 million, primarily due to lower volumes from well shut-ins from our customers.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $5.4 million, resulting from:

•A $4.7 million decrease from our Louisiana gas assets due to lower processing margins and volumes attributable to a less favorable processing environment, the expiration of certain firm transportation contracts, and decreased volumes.

•A $4.3 million decrease from our ORV crude assets primarily due to lower volumes.

•A $3.6 million increase from our NGL transmission and fractionation assets, which was primarily due to a settlement payment received as the result of a contract dispute.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $29.3 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


	Three Months Ended June 30,
	2020		2019
Realized swaps:
Crude swaps	$	(2.4)	$	(2.5)
NGL swaps	(0.4)		3.7
Gas swaps	(0.8)		(1.5)
Realized loss on derivatives	(3.6)		(0.3)

Unrealized swaps:
Crude swaps	(3.6)		4.9
NGL swaps	(14.4)		1.3
Gas swaps	(0.8)		1.0
Change in fair value of derivatives	(18.8)		7.2

Gain (loss) on derivatives	$	(22.4)	$	6.9

Certain gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers agree to ship and/or process a minimum volume of commodity on our systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually determined fee based upon the shortfall between actual commodity volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods.

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Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):


	Three Months Ended June 30,
	2020		2019
Permian Segment	$	(1.7)	$	3.9
Oklahoma Segment	15.1		—
Total	$	13.4	$	3.9

Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020.

Operating Expenses. Operating expenses were $88.1 million for the three months ended June 30, 2020 compared to $117.9 million for the three months ended June 30, 2019, a decrease of $29.8 million, or 25.3%. The primary contributors to the total decrease by segment were as follows (in millions):


	Three Months Ended June 30,						Change
	2020		2019		$		%
Permian Segment	$	22.7	$	28.4	$	(5.7)	(20.1)	%
North Texas Segment	18.5		25.8		(7.3)		(28.3)	%
Oklahoma Segment	19.4		26.1		(6.7)		(25.7)	%
Louisiana Segment	27.5		37.6		(10.1)		(26.9)	%
Total	$	88.1	$	117.9	$	(29.8)	(25.3)	%

•Permian Segment. Operating expenses in the Permian segment decreased $5.7 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in construction fees and services, and sales and use tax.

•North Texas Segment. Operating expenses in the North Texas segment decreased $7.3 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in operations and maintenance, ad valorem tax, sales and use tax, and compressor rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $6.7 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, operations and maintenance, construction fees and services, and compressor and treater rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $10.1 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, utilities, construction fees and services, ad valorem tax, and vehicle expenses.

General and Administrative Expenses. General and administrative expenses were $23.5 million for the three months ended June 30, 2020 compared to $32.2 million for the three months ended June 30, 2019, a decrease of $8.7 million, or 27.0%. The primary contributors to the decrease were as follows:

•Labor costs and unit-based compensation costs decreased $3.8 million, which was primarily due to a reduction in workforce in April 2020.

•Expenses related to fees and services, travel, rents and leases, and insurance decreased $3.2 million primarily due to general cost saving initiatives and decreased activity as a result of COVID-19.

Depreciation and Amortization. Depreciation and amortization was $158.2 million for the three months ended June 30, 2020 compared to $153.7 million for the three months ended June 30, 2019, an increase of $4.5 million, or 2.9%. This increase was primarily due to new assets placed in service in the Permian, Oklahoma, and Louisiana segments, as well as accelerated depreciation on certain non-core assets. These increases were partially offset by the impairment of Louisiana segment assets in the first quarter of 2020 and the conclusion of a finance lease in the North Texas segment in 2019.

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Impairments. For the three months ended June 30, 2020, we recognized a $1.5 million impairment on property and equipment related to cancelled projects. See “Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments.

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $26.7 million for the three months ended June 30, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. See “Item 1. Financial Statements—Note 5” for additional information.

Interest Expense. Interest expense was $55.2 million for the three months ended June 30, 2020 compared to $54.3 million for the three months ended June 30, 2019, an increase of $0.9 million, or 1.7%. Interest expense consisted of the following (in millions):


	Three Months Ended June 30,
	2020		2019
ENLK and ENLC Senior Notes	$	43.3	$	43.4
Term Loan	4.2		8.5
Consolidated Credit Facility	4.1		3.7
Capitalized interest	(1.3)		(1.8)
Amortization of debt issue costs and net discounts (premiums)	1.2		1.0
Interest rate swap	3.7		(0.3)
Other	—		(0.2)
Total	$	55.2	$	54.3

Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $0.7 million for the three months ended June 30, 2020 compared to income of $4.7 million for the three months ended June 30, 2019, a decrease of $5.4 million. The decrease was primarily attributable to a reduction of income of $4.9 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of $0.5 million from our Cedar Cove JV.

Income Tax Expense. Income tax expense was $11.7 million for the three months ended June 30, 2020 compared to an income tax benefit of $5.4 million for the three months ended June 30, 2019. The increase in income tax expense was primarily attributable to higher income between periods and tax deficiencies recorded upon the vesting of restricted incentive units. See “Item 1. Financial Statements—Note 6” for additional information.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Gross Operating Margin. Gross operating margin was $748.0 million for the six months ended June 30, 2020 compared to $825.7 million for the six months ended June 30, 2019, a decrease of $77.7 million, or 9.4%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment decreased $4.2 million, resulting from:

•An $11.6 million decrease due to the expiration of an MVC related to our South Texas assets in July 2019.

•A $3.7 million increase due to volume growth in our Midland Basin crude assets.

•A $2.9 million increase due to volume growth in our Delaware Basin crude assets.

•A $1.9 million decrease related to our Midland Basin gas assets.

•A $2.7 million increase related to our Delaware Basin gas assets.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $18.2 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $30.3 million. Gross operating margin contributed by our Oklahoma gas assets decreased $31.2 million, which was partially due to lower volumes from our existing customers, and was partially offset by a $0.9 million increase in gross operating margin contributed by our Oklahoma crude assets.

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•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $13.1 million, resulting from:

•A $12.4 million decrease from our Louisiana gas assets due to lower processing margins and volumes attributable to a less favorable processing environment, the expiration of certain firm transportation contracts, and decreased volumes.

•A $6.1 million decrease from our ORV crude assets primarily due to lower volumes.

•A $5.4 million increase from our NGL transmission and fractionation assets, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019 and a settlement payment received as the result of a contract dispute.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $11.9 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


	Six Months Ended June 30,
	2020		2019
Realized swaps:
Crude swaps	$	(3.0)	$	0.8
NGL swaps	6.3		5.6
Gas swaps	(0.7)		(2.9)
Realized gain on derivatives	2.6		3.5

Unrealized swaps:
Crude swaps	2.5		4.5
NGL swaps	(7.0)		(2.3)
Gas swaps	(1.3)		3.0
Change in fair value of derivatives	(5.8)		5.2

Gain (loss) on derivatives	$	(3.2)	$	8.7

Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):


	Six Months Ended June 30,
	2020		2019
Permian	$	0.3	$	7.7
Oklahoma	24.9		—
Total	$	25.2	$	7.7

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Operating Expenses. Operating expenses were $188.8 million for the six months ended June 30, 2020 compared to $232.4 million for the six months ended June 30, 2019, a decrease of $43.6 million, or 18.8%. The primary contributors to the decrease by segment were as follows (in millions):


	Six Months Ended June 30,						Change
	2020		2019		$		%
Permian Segment	$	48.2	$	56.2	$	(8.0)	(14.2)	%
North Texas Segment	39.0		51.5		(12.5)		(24.3)	%
Oklahoma Segment	42.3		51.5		(9.2)		(17.9)	%
Louisiana Segment	59.3		73.2		(13.9)		(19.0)	%
Total	$	188.8	$	232.4	$	(43.6)	(18.8)	%

•Permian Segment. Operating expenses in the Permian segment decreased $8.0 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, construction fees and services, sales and use tax, and vehicle expenses.

•North Texas Segment. Operating expenses in the North Texas segment decreased $12.5 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, operations and maintenance, construction fees and services, ad valorem tax, sales and use tax, and treater and compressor rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $9.2 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, construction fees and services, operations and maintenance, utilities, ad valorem tax, and treater rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $13.9 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, construction fees and services, ad valorem tax, and vehicle expenses.

General and Administrative Expenses. General and administrative expenses were $53.9 million for the six months ended June 30, 2020 compared to $83.6 million for the six months ended June 30, 2019, a decrease of $29.7 million, or 35.5%. The primary contributors to the decrease were as follows:

•Transaction costs decreased $13.9 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019.

•Labor costs and unit-based compensation decreased $8.9 million due to a reduction in workforce and lower bonus accrual.

•Fees and services expense, rents and leases, and insurance expenses decreased $4.1 million, which was primarily due to general cost saving initiatives.

Depreciation and Amortization. Depreciation and amortization was $321.0 million for the six months ended June 30, 2020 compared to $305.8 million for the six months ended June 30, 2019, an increase of $15.2 million, or 5.0%. This increase was primarily due to new assets placed in service in the Oklahoma segment, as well as accelerated depreciation on certain non-core assets. These increases were partially offset by the impairment of Louisiana segment assets in the first quarter of 2020 and the conclusion of a finance lease in the North Texas segment in 2019.

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Impairments. For the six months ended June 30, 2020, we recognized impairment expense related to goodwill and property and equipment. For the six months ended June 30, 2019 we recognized impairment expense related to goodwill. See “Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments and “Item 1. Financial Statements—Note 3” for additional information on our goodwill impairments. Impairment expense is composed of the following amounts (in millions):


	Six Months Ended June 30,
	2020		2019
Goodwill impairment	$	184.6	$	186.5
Property impairment	168.0		—
Cancelled projects	1.9		—
Total	$	354.5	$	186.5

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $32.0 million for the six months ended June 30, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. See “Item 1. Financial Statements—Note 5” for additional information.

Loss on secured term loan receivable. We recorded a $52.9 million loss in our consolidated statement of operations for the six months ended June 30, 2019 related to the write-off of the secured term loan receivable.

Interest Expense. Interest expense was $110.8 million for the six months ended June 30, 2020 compared to $103.9 million for the six months ended June 30, 2019, an increase of $6.9 million, or 6.6%. Interest expense consisted of the following (in millions):


	Six Months Ended June 30,
	2020		2019
ENLK and ENLC Senior Notes	$	87.3	$	83.4
Term Loan	10.6		17.1
Consolidated Credit Facility	8.2		6.1
Capitalized interest	(2.5)		(3.8)
Amortization of debt issue costs and net discounts (premiums)	2.2		2.8
Interest rate swap	5.0		(0.3)
Other	—		(1.4)
Total	$	110.8	$	103.9

Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $1.0 million for the six months ended June 30, 2020 compared to $10.0 million for the six months ended June 30, 2019, a decrease of $9.0 million. The decrease was primarily attributable to a reduction of income of $8.8 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of $0.2 million from our Cedar Cove JV.

Income Tax Expense. Income tax benefit was $22.0 million for the six months ended June 30, 2020 compared to an income tax benefit of $3.6 million for the six months ended June 30, 2019. The increase in income tax benefit was primarily attributable to lower income between periods. See “Item 1. Financial Statements—Note 6” for additional information.

Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $52.1 million for the six months ended June 30, 2020 compared to net income of $66.7 million for the six months ended June 30, 2019, a decrease of $14.6 million. This decrease was primarily due to the conversion of ENLK common units into ENLC common units as a result of the Merger in the first quarter of 2019. Subsequent to the Merger, ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of the Ascension JV, and other minor non-controlling interests.

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Critical Accounting Policies

Information regarding our critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019, except as described below.

Property and Equipment

In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.

During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. For the six months ended June 30, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows, and a $1.9 million impairment on property and equipment related to cancelled projects.

Goodwill Impairment

We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $316.8 million for the six months ended June 30, 2020 compared to $521.5 million for the six months ended June 30, 2019. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):


	Six Months Ended June 30,
	2020		2019
Operating cash flows before working capital	$	418.9	$	429.5
Changes in working capital	(102.1)		92.0

Operating cash flows before changes in working capital decreased $10.6 million for the six months ended June 30, 2020 compared to the six months ended June 30, 2019. The primary contributors to the decrease in operating cash flows were as follows:

•Gross operating margin, excluding non-cash commodity swap activity, decreased $67.9 million.

•Interest expense, excluding amortization of debt issue costs and net discounts (premium) of notes, increased $7.5 million.

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These changes to operating cash flows were offset by the following:

•Operating expenses excluding unit-based compensation decreased $45.4 million primarily due to a reduction in workforce. For more information, see “Results of Operations.”

•General and administrative expenses excluding unit-based compensation decreased $25.0 million primarily due to a reduction in costs across our platform. For more information, see “Results of Operations.”

The changes in working capital for the six months ended June 30, 2020 compared to the six months ended June 30, 2019 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.

Cash Flows from Investing Activities. Net cash used in investing activities was $202.0 million for the six months ended June 30, 2020, compared to $426.9 million for the six months ended June 30, 2019. Investing cash flows are primarily related to capital expenditures, which decreased from $428.4 million for the six months ended June 30, 2019 to $203.6 million for the six months ended June 30, 2020. The decrease was primarily due to reduced capital spending plans for 2020.

Cash Flows from Financing Activities. Net cash used in financing activities was $140.2 million for the six months ended June 30, 2020 compared to $136.0 million for the six months ended June 30, 2019. Our primary financing activities consisted of the following (in millions):


	Six Months Ended June 30,
	2020		2019
Net borrowings on the Consolidated Credit Facility	$	50.0	$	200.0
Net repurchases on ENLK senior unsecured notes	(35.2)		—
Net borrowings (repurchases) on the 2029 Notes	(0.8)		500.0
Net repayments on the ENLK 2019 unsecured senior notes	—		(400.0)
Net repayments on the ENLC Credit Facility	—		(111.4)
Contributions by non-controlling interests (1)	50.3		45.2
Distribution to members	(139.8)		(188.2)
Distributions to ENLK common units held by public unitholders (2)	—		(104.8)
Distributions to Series B Preferred Unitholders (3)	(33.6)		(33.2)
Distributions to Series C Preferred Unitholders (3)	(12.0)		(12.0)
Distributions to joint venture partners (4)	(15.0)		(12.7)

____________________________

(1)Represents contributions from NGP to the Delaware Basin JV.

(2)Subsequent to the closing of the Merger, ENLK no longer has publicly held common units.

(3)See “Item 1. Financial Statements—Note 7” for information on distributions to holders of the Series B and Series C Preferred Units.

(4)Represents distributions to NGP for its ownership in the Delaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other minor non-controlling interests.

Capital Requirements. We expect our remaining 2020 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately $40 million to $100 million, which is net of approximately $10 million to $20 million from our joint venture partners. Our primary capital projects for the remainder of 2020 include the construction of the Tiger Plant in the Delaware Basin and continued development of our existing systems. See “Other Recent Developments” for further details.

We expect to fund capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. In 2020, it is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of June 30, 2020.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2020 is as follows (in millions):


	Payments Due by Period
	Total		Remainder 2020		2021		2022		2023		2024		Thereafter
Long-term debt obligations	$	3,532.3	$	—	$	—	$	—	$	—	$	521.8	$	3,010.5
Term Loan	850.0		—		850.0		—		—		—		—
Consolidated Credit Facility	400.0		—		—		—		—		400.0		—
Interest payable on fixed long-term debt obligations	2,412.4		86.7		173.1		173.1		173.1		161.7		1,644.7
Operating lease obligations	128.2		10.6		17.0		12.2		10.2		9.5		68.7
Purchase obligations	13.0		13.0		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (1)	199.6		31.0		39.8		31.8		28.1		33.0		35.9
Inactive easement commitment (2)	10.0		—		—		10.0		—		—		—
Total contractual obligations	$	7,545.5	$	141.3	$	1,079.9	$	227.1	$	211.4	$	1,126.0	$	4,759.8

____________________________

(1)Consists of pipeline capacity payments for firm transportation and deficiency agreements.

(2)Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.

The above table does not include any physical or financial contract purchase commitments for natural gas and NGLs due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount that is not already disclosed in the table above.

The interest payable related to the Consolidated Credit Facility and the Term Loan are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Consolidated Credit Facility and the Term Loan, which vary from time to time.

Our contractual cash obligations for the remainder of 2020 are expected to be funded from cash flows generated from our operations.

Indebtedness

In December 2018, we entered into the Consolidated Credit Facility, which permits us to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. As of June 30, 2020, there was $400.0 million in outstanding borrowings under the Consolidated Credit Facility and $23.0 million in outstanding letters of credit.

In addition, as of June 30, 2020, we have $3.5 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047 and $850.0 million in outstanding principal on the Term Loan.

See “Item 1. Financial Statements—Note 5” for more information on our outstanding debt instruments.

Recent Accounting Pronouncements

See “Item 1. Financial Statements—Note 2” for more information on recently issued and adopted accounting pronouncements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking

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statements include, but are not limited to, statements about when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, future cost savings or operational initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic on us and our financial results and operations, and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operation, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) outbreak on our business, financial condition, and results of operation, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP’s own interests to the detriment of our unitholders, (c) GIP’s ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or businesses, (d) a default under GIP’s credit facility could result in a change in control of us, could adversely affect the price of our common units, and could result in a default under our credit facility, (e) the dependence on Devon for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect Devon or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) construction risks in our major development projects, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, and (t) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019 and in Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs, condensate, and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the CFTC to regulate certain markets for derivative products, including OTC derivatives. The CFTC has issued several relevant regulations, and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the legislation to cause significant portions of derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not, and, as a result, the final form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. The CFTC proposed new rules in January 2020 (withdrawing previously proposed rules from November 2013 and December 2016) that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC sought comment on the position limits rules as reproposed and revised, but the new rules have not yet been issued in final form, and the impact of any final provisions on us is uncertain at this time.

The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative

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contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Commodity Price Risk

We are subject to risks due to fluctuations in commodity prices. Approximately 94% of our gross operating margin for the six months ended June 30, 2020 was generated from arrangements with fee-based structures with minimal direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently process gas under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below.

1.Fee-based contracts. Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of volume processed or (2) arrangements where we purchase and resell commodities in connection with providing the related processing service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities.

2.Processing margin contracts. Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the six months ended June 30, 2020, less than 1% of our gross operating margin was generated from processing margin contracts.

3.POL contracts. Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under POL contracts, but they do decline during periods of low liquids prices.

4.POP contracts. Under these contracts, we receive a fee in the form of a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under POP contracts, but they do decline during periods of low natural gas and liquids prices.

For the six months ended June 30, 2020, approximately 4% of our gross operating margin was generated from POL or POP contracts.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using OTC derivative financial instruments with only certain well-capitalized counterparties which have been approved in accordance with our commodity risk management policy.

We have hedged our exposure to fluctuations in prices for natural gas, NGLs, and crude oil volumes produced for our account. We have tailored our hedges to generally match the product composition and the delivery points to those of our physical equity volumes. The hedges cover specific products based upon our expected equity composition.

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The following table sets forth certain information related to derivative instruments outstanding at June 30, 2020 mitigating the risks associated with the gas processing and fractionation components of our business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by Oil Price Information Service. The relevant index price for natural gas is Henry Hub Gas Daily as defined by the pricing dates in the swap contracts.

Period

Underlying

Notional Volume

We Pay

We Receive (1)

Net Fair Value
Asset/(Liability)
(In millions)

July 2020 - May 2021

Ethane

2,143 (MBbls)

$0.1896/gal

Index

(2.8)

July 2020 - May 2021

Propane

1,491 (MBbls)

Index

$0.4670/gal

(1.8)

July 2020 - May 2021

Normal butane

400 (MBbls)

Index

$0.4867/gal

0.1

July 2020 - December 2020

Natural gasoline

155 (MBbls)

Index

$0.7304/gal

(1.3)

July 2020 - October 2021

Natural gas

102,842 (MMBtu/d)

Index

$1.6930/MMBtu

(0.8)

July 2020 - January 2021

Crude and condensate

1,135 (MBbls)

Index

$39.48/Bbl

(0.8)

July 2020 - December 2022

Crude and condensate

10,166 (MBbls)

$1.851/Bbl

Index (2)

10.0

2.6

____________________________

(1)Weighted average.

(2)Represents the WTI Houston and WTI Midland differential.

Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

As of June 30, 2020, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value asset of $2.6 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in a change of approximately $8.6 million in the net fair value of these contracts as of June 30, 2020.

Interest Rate Risk

We are exposed to interest rate risk on the Consolidated Credit Facility and the Term Loan. At June 30, 2020, we had $400.0 million and $850.0 million in outstanding borrowings under the Consolidated Credit Facility and the Term Loan, respectively. In April 2019, we entered into $850.0 million of interest rate swaps to reduce the variability of cash outflows associated with interest payments related to our long-term debt with variable interest rates. These swaps have been designated as cash flow hedges. See “Item 1. Financial Statements—Note 11” for more information on our outstanding derivatives. A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $4.0 million and $8.5 million for the Consolidated Credit Facility and the Term Loan, respectively. This change in interest expense would be partially offset by an $8.5 million change related to our open interest rate swap hedge.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2029 as these are fixed-rate obligations. As of June 30, 2020, the estimated fair value of the senior unsecured notes was approximately $2,541.1 million, based on the market prices of ENLK’s and our publicly traded debt at June 30, 2020. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1.0% in interest rates. Such an increase in interest rates would result in an approximate $158.5 million decrease in fair value of the senior unsecured notes at June 30, 2020. See “Item 1. Financial Statements—Note 5” for more information on our outstanding indebtedness.

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Item 4. Controls and Procedures

a.Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of EnLink Midstream Manager, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (June 30, 2020), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

b.Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended June 30, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are 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 would not individually or in the aggregate have a material adverse effect on our financial position, results of operations, or cash flows.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019, as supplemented by Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the three months ended June 30, 2020, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted incentive units.


Period	Total Number of Units Purchased (1)	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Units that May Yet Be Purchased under the Plans or Programs
April 1, 2020 to April 30, 2020	58,159	$	1.06	—	—
May 1, 2020 to May 31, 2020	27,145	1.36		—	—
June 1, 2020 to June 30, 2020	41,018	2.73		—	—
Total	126,322	$	1.67	—	—

____________________________

(1)The common units were not re-acquired pursuant to any repurchase plan or program.

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Item 6. Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):


Number		Description

3.1	—	Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, filed with the Commission on November 20, 2013, file No. 333-192419).
3.2	—	Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to our Registration Statement on Form S-4, filed with the Commission on January 21, 2014, file No. 333-192419).
3.3	—	Second Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of January 25, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
3.4	—	Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.5	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.6	—	Second Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36336).
3.7	—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, filed with the Commission on March 10, 2014, file No. 333-194465).
3.9	—	Fourth Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36366).
3.10	—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, filed with the Commission on August 7, 2012, file No. 333-97779).
3.11	—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Commission on August 7, 2012, file No. 000-50067).
3.12	—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
3.13	—	Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 16, 2017, filed with the Commission on June 19, 2017, file No. 001-36340).
3.14	—	Tenth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of January 25, 2019 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
















31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	Certification of the Principal Certification of the Principal Financial Officer.
32.1 *	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101 *	—	The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019, (ii) Consolidated Statements of Operations for the three and six months ended June 30, 2020 and 2019, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended June 30, 2020 and 2019 and March 31, 2020 and 2019, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2020 and 2019, and (v) the Notes to Consolidated Financial Statements.
104 *	—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

____________________________

* Filed herewith.

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SIGNATURES

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


	EnLink Midstream, LLC

	By:	EnLink Midstream Manager, LLC,
		its managing member

	By:	/s/ PABLO G. MERCADO
		Pablo G. Mercado
		Executive Vice President and Chief Financial Officer

August 5, 2020