10-Q

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 September 30, 2020

OR

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

For the transition period from               to

Commission file number: 001-36336

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 Liability Company Interests	ENLC	The New York Stock Exchange

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 October 29, 2020, the Registrant had 489,746,802 common units outstanding.

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	33
3.	Quantitative and Qualitative Disclosures About Market Risk	51
4.	Controls and Procedures	54
	PART II—OTHER INFORMATION
1.	Legal Proceedings	55
1A.	Risk Factors	55
2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
5.	Other Information	55
6.	Exhibits	56

2

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.
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.
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.
MMbbls	Million barrels.
MMbtu	Million British thermal units.
MMcf	Million cubic feet.
MVC	Minimum volume commitment.

3

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 in the Delaware Basin owned by the Delaware Basin JV.
White Star	White Star Petroleum, LLC.

4

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)

	September 30, 2020		December 31, 2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78.9	$	77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.5, respectively	58.3		36.2
Accrued revenue and other	352.9		460.1
Fair value of derivative assets	9.6		12.9
Other current assets	81.7		57.8
Total current assets	581.4		644.4
Property and equipment, net of accumulated depreciation of $3,775.9 and $3,418.6, respectively	6,742.0		7,081.3
Intangible assets, net of accumulated amortization of $638.0 and $545.9, respectively	1,156.2		1,249.9
Goodwill	—		184.6
Investment in unconsolidated affiliates	41.9		43.1
Fair value of derivative assets	5.4		4.3
Other assets, net	140.3		128.2
Total assets	$	8,667.2	$	9,335.8
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	54.4	$	70.6
Accounts payable to related party	0.9		1.1
Accrued gas, NGLs, condensate, and crude oil purchases	214.8		354.8
Fair value of derivative liabilities	33.1		14.4
Other current liabilities	198.8		206.2
Total current liabilities	502.0		647.1
Long-term debt	4,650.0		4,764.3
Asset retirement obligations	16.1		15.5
Other long-term liabilities	83.5		90.8
Fair value of derivative liabilities	4.5		6.8
Redeemable non-controlling interest	—		5.2
Members’ equity:
Members’ equity (489,734,530 and 487,791,612 units issued and outstanding, respectively)	1,701.2		2,135.5
Accumulated other comprehensive loss	(19.0)		(11.0)
Non-controlling interest	1,728.9		1,681.6
Total members’ equity	3,411.1		3,806.1
Total liabilities and members’ equity	$	8,667.2	$	9,335.8

See accompanying notes to consolidated financial statements.

5

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Unaudited)
Revenues:
Product sales	$	696.1	$	1,137.2	$	2,121.6	$	4,118.5
Midstream services	237.5		263.3		716.2		762.5
Gain (loss) on derivative activity	(5.1)		7.5		(8.3)		16.2
Total revenues	928.5		1,408.0		2,829.5		4,897.2
Operating costs and expenses:
Cost of sales	549.5		999.5		1,702.5		3,663.0
Operating expenses	94.3		119.2		283.1		351.6
General and administrative	25.7		38.5		79.6		122.1
(Gain) loss on disposition of assets	(1.8)		(3.0)		2.8		(2.9)
Depreciation and amortization	160.3		157.3		481.3		463.1
Impairments	—		—		354.5		186.5
Loss on secured term loan receivable	—		—		—		52.9
Total operating costs and expenses	828.0		1,311.5		2,903.8		4,836.3
Operating income (loss)	100.5		96.5		(74.3)		60.9
Other income (expense):
Interest expense, net of interest income	(55.5)		(56.6)		(166.3)		(160.5)
Gain on extinguishment of debt	—		—		32.0		—
Income (loss) from unconsolidated affiliates	(0.2)		4.0		0.8		14.0
Other income (expense)	0.4		(0.1)		0.4		0.1
Total other expense	(55.3)		(52.7)		(133.1)		(146.4)
Income (loss) before non-controlling interest and income taxes	45.2		43.8		(207.4)		(85.5)
Income tax benefit (expense)	(6.0)		(6.3)		16.0		(2.7)
Net income (loss)	39.2		37.5		(191.4)		(88.2)
Net income attributable to non-controlling interest	26.6		25.7		78.7		92.4
Net income (loss) attributable to ENLC	$	12.6	$	11.8	$	(270.1)	$	(180.6)
Net income (loss) attributable to ENLC per unit:
Basic common unit	$	0.03	$	0.02	$	(0.55)	$	(0.40)
Diluted common unit	$	0.03	$	0.02	$	(0.55)	$	(0.40)

See accompanying notes to consolidated financial statements.

6

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Unaudited)
Net income (loss)	$	39.2	$	37.5	$	(191.4)	$	(88.2)
Gain (loss) on designated cash flow hedge (1)	3.6		(1.3)		(8.0)		(11.2)
Comprehensive income (loss)	42.8		36.2		(199.4)		(99.4)
Comprehensive income attributable to non-controlling interest	26.6		25.7		78.7		92.4
Comprehensive income (loss) attributable to ENLC	$	16.2	$	10.5	$	(278.1)	$	(191.8)

____________________________

(1)Includes a tax expense of $1.1 million and a tax benefit of $2.4 million for the three and nine months ended September 30, 2020, respectively, and a tax benefit of $0.5 million and $4.1 million for the three and nine months ended September 30, 2019, respectively.

See accompanying notes to consolidated financial statements.

7

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		—
Conversion of restricted units for common units, net of units withheld for taxes	(0.4)		0.2	—		—		(0.4)		—
Unit-based compensation	7.2		—	—		—		7.2		—
Contributions from non-controlling interests	—		—	—		1.9		1.9		—
Distributions	(46.4)		—	—		(23.3)		(69.7)		(0.3)
Gain on designated cash flow hedge (3)	—		—	3.6		—		3.6		—
Fair value adjustment related to redeemable non-controlling interest	(0.3)		—	—		—		(0.3)		0.3
Net income	12.6		—	—		26.6		39.2		—
Balance, September 30, 2020	$	1,701.2	489.7	$	(19.0)	$	1,728.9	$	3,411.1	$	—

____________________________

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

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

(3)Includes a tax expense of $1.1 million.

See accompanying notes to consolidated financial statements.

8

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
Conversion of restricted units for common units, net of units withheld for taxes	(2.1)		0.4	—		—		(2.1)		—
Unit-based compensation	11.1		—	—		—		11.1		—
Contributions from non-controlling interests	—		—	—		33.4		33.4		—
Distributions	(139.8)		—	—		(22.1)		(161.9)		(0.3)
Loss on designated cash flow hedge (2)	—		—	(1.3)		—		(1.3)		—
Fair value adjustment related to redeemable non-controlling interest	0.1		—	—		—		0.1		(0.1)
Net income	11.8		—	—		25.6		37.4		0.1
Balance, September 30, 2019	$	3,205.7	487.6	$	(13.2)	$	1,670.9	$	4,863.4	$	5.5

____________________________

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

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

See accompanying notes to consolidated financial statements.

9

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)

	Nine Months Ended September 30,
	2020		2019
	(Unaudited)
Cash flows from operating activities:
Net loss	$	(191.4)	$	(88.2)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairments	354.5		186.5
Depreciation and amortization	481.3		463.1
Loss on secured term loan receivable	—		52.9
Deferred income tax (benefit) expense	(17.1)		0.7
Non-cash unit-based compensation	24.6		31.2
(Gain) loss on derivatives recognized in net loss	8.3		(16.2)
Cash settlements on derivatives	(1.0)		12.5
Gain on extinguishment of debt	(32.0)		—
Amortization of debt issue costs, net discount (premium) of notes	3.1		3.9
Distribution of earnings from unconsolidated affiliates	1.6		14.7
Income from unconsolidated affiliates	(0.8)		(14.0)
Other operating activities	2.1		(5.0)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	85.3		338.6
Natural gas and NGLs inventory, prepaid expenses, and other	(12.7)		2.7
Accounts payable, accrued product purchases, and other accrued liabilities	(144.8)		(205.9)
Net cash provided by operating activities	561.0		777.5
Cash flows from investing activities:
Additions to property and equipment	(254.4)		(594.5)
Proceeds from sale of property	7.2		13.7
Other investing activities	(3.5)		(2.2)
Net cash used in investing activities	(250.7)		(583.0)
Cash flows from financing activities:
Proceeds from borrowings	690.0		2,855.0
Payments on borrowings	(776.0)		(2,591.4)
Debt financing costs	—		(10.0)
Conversion of restricted units, net of units withheld for taxes	(4.7)		(10.5)
Distribution to members	(186.2)		(328.0)
Distributions to non-controlling interests	(84.2)		(185.1)
Contributions by non-controlling interests	52.2		78.6
Other financing activities	0.1		(1.3)
Net cash used in financing activities	(308.8)		(192.7)
Net increase in cash and cash equivalents	1.5		1.8
Cash and cash equivalents, beginning of period	77.4		100.4
Cash and cash equivalents, end of period	$	78.9	$	102.2
Supplemental disclosures of cash flow information:
Cash paid for interest	$	125.7	$	128.0
Cash paid (refunded) for income taxes	$	(0.1)	$	2.8
Non-cash investing activities:
Non-cash accrual of property and equipment	$	(27.2)	$	24.6
Right-of-use assets obtained in exchange for operating lease liabilities	$	9.1	$	98.4
Non-cash financing activities:
Redemption of non-controlling interest	$	(4.0)	$	—

See accompanying notes to consolidated financial statements.

10

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 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

11

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 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 energy, volatility in the market prices for these commodities, and a significant and persistent reduction in the market price of crude oil. As a result of the demand destruction, reduced commodity prices, and an uncertain timeline for full recovery, many oil and natural gas producers, including some of our customers, have curtailed their current drilling and production activity and reduced or slowed down their plans for future drilling and production activity. As a result of these decreases in producer activity, we experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems during portions of the first and second quarters, although volumes have since been restored nearly to pre-pandemic levels.

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 whether 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 that exist as of the date of this report will be extended or new measures will be reinstated. As a result, there is significant uncertainty regarding whether market dislocations will continue or increase and how significantly and how long they may 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.

12

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 nine months ended September 30, 2020, we had contractual commitments of $44.8 million and $128.0 million under our MVC contracts, respectively, and recorded $14.0 million and $39.2 million of revenue due to volume shortfalls, respectively.

MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)	$	65.3
2021	119.7
2022	102.1
2023	91.5
2024	77.4
Thereafter	144.9
Total	$	600.9

____________________________

(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 nine months ended September 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. For the three months ended September 30, 2020, we did not recognize any impairment related to property and equipment.

13

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, the 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 included in “Other current liabilities” on the consolidated balance sheet as of September 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 nine months ended September 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.

14

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 nine months ended September 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 nine months ended September 30, 2020.

Goodwill Impairment Analysis for the nine months ended September 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
Nine Months Ended September 30, 2020
Customer relationships, beginning of period	$	1,795.8	$	(545.9)	$	1,249.9
Amortization expense	—		(92.7)		(92.7)
Retirements (1)	(1.6)		0.6		(1.0)
Customer relationships, end of period	$	1,794.2	$	(638.0)	$	1,156.2

____________________________

(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 for each of the three months ended September 30, 2020 and 2019, and $92.7 million and $92.8 million for the nine months ended September 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)	$	30.8
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8
Total	$	1,156.2

15

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 nine months ended September 30, 2020, we recorded cost of sales of $2.0 million and $6.2 million, respectively, and for the three and nine months ended September 30, 2019, we recorded cost of sales of $4.1 million and $18.0 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 $0.9 million and $1.1 million at September 30, 2020 and December 31, 2019, respectively.

Transactions with GIP. For the three and nine months ended September 30, 2020, we recorded general and administrative expenses of $0.2 million related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three and nine months ended September 30, 2019.

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

	September 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)	$	300.0	$	—	$	300.0	$	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		1.1		522.9		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		(5.7)		444.3		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	$	4,682.3	$	(5.9)	4,676.4		$	4,800.0	$	(5.9)	4,794.1
Debt issuance cost (3)					(26.4)						(29.8)
Long-term debt, net of unamortized issuance cost					$	4,650.0					$	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 September 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 September 30, 2020 and December 31, 2019, respectively.

(3)Net of amortization of $13.7 million and $10.9 million at September 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 ($300.0 million as of September 30, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($19.3 million as of September 30, 2020). The obligations under the Consolidated Credit Facility are unsecured.

16

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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. 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 September 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 September 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 September 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.

17

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Senior Unsecured Notes Repurchases

For the nine months ended September 30, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. We and ENLK did not make any payments to repurchase senior notes during the three months ended September 30, 2020. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions):

	Nine Months Ended September 30, 2020
Debt repurchased	$	67.7
Aggregate payments	(36.0)
Net discount on repurchased debt	(0.3)
Accrued interest on repurchased debt	0.6
Gain on extinguishment of debt	$	32.0

(6) Income Taxes

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Current income tax expense	$	(0.4)	$	(0.7)	$	(1.1)	$	(2.0)
Deferred income tax benefit (expense)	(5.6)		(5.6)		17.1		(0.7)
Income tax benefit (expense)	$	(6.0)	$	(6.3)	$	16.0	$	(2.7)

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Expected income tax benefit (expense) based on federal statutory rate	$	(3.6)	$	(3.8)	$	60.0	$	37.4
State income tax benefit (expense), net of federal benefit	(0.6)		(0.7)		6.4		3.6
Unit-based compensation (1)	(1.6)		(1.3)		(6.0)		(1.3)
Non-deductible expense related to goodwill impairment	—		—		(43.4)		(43.8)
Other	(0.2)		(0.5)		(1.0)		1.4
Income tax benefit (expense)	$	(6.0)	$	(6.3)	$	16.0	$	(2.7)

____________________________

(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 September 30, 2020, we had $51.6 million of deferred tax assets, net of $446.4 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.

18

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 September 30, 2020 and December 31, 2019, there were 60,047,665 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 nine months ended September 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
Third Quarter of 2020	150,119	$	16.9	November 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
Third Quarter of 2019	148,627	$	17.1	November 13, 2019

b.Series C Preferred Units

As of September 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 nine months ended September 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.

19

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Distributed earnings allocated to:
Common units (1)(2)	$	45.9	$	138.0	$	137.6	$	385.2
Unvested restricted units (1)(2)	0.7		1.6		2.3		4.6
Total distributed earnings	$	46.6	$	139.6	$	139.9	$	389.8
Undistributed loss allocated to:
Common units	$	(33.4)	$	(126.3)	$	(403.0)	$	(563.6)
Unvested restricted units	(0.6)		(1.5)		(7.0)		(6.8)
Total undistributed loss	$	(34.0)	$	(127.8)	$	(410.0)	$	(570.4)
Net income (loss) allocated to:
Common units	$	12.5	$	11.7	$	(265.4)	$	(178.4)
Unvested restricted units	0.1		0.1		(4.7)		(2.2)
Total net income (loss)	$	12.6	$	11.8	$	(270.1)	$	(180.6)
Basic and diluted net income (loss) per unit:
Basic	$	0.03	$	0.02	$	(0.55)	$	(0.40)
Diluted	$	0.03	$	0.02	$	(0.55)	$	(0.40)

____________________________

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

(2)For the nine months ended September 30, 2020, distributed earnings included a declared distribution of $0.09375 per unit payable on November 13, 2020, $0.09375 per unit paid on August 13, 2020, and $0.09375 per unit paid on May 13, 2020. For the nine months ended September 30, 2019, distributed earnings included distributions of $0.283 per unit paid on November 13, 2019, $0.283 per unit paid on August 13, 2019, and $0.279 per unit paid on May 14, 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 September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	489.7	487.4	489.2	455.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	489.7	487.4	489.2	455.9
Dilutive effect of non-vested restricted units (1)	1.2	2.0	—	—
Total weighted average diluted common units outstanding	490.9	489.4	489.2	455.9

____________________________

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

20

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 nine months ended September 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
Third Quarter of 2020	$	0.09375	November 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
Third Quarter of 2019	$	0.283	November 13, 2019

(9) Investment in Unconsolidated Affiliates

As of September 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
GCF
Distributions	$	—	$	5.1	$	1.6	$	14.7
Equity in income	$	0.4	$	4.4	$	2.5	$	15.3
Cedar Cove JV
Distributions	$	—	$	0.3	$	0.4	$	0.8
Equity in loss	$	(0.6)	$	(0.4)	$	(1.7)	$	(1.3)
Total
Distributions	$	—	$	5.4	$	2.0	$	15.5
Equity in income (loss)	$	(0.2)	$	4.0	$	0.8	$	14.0

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

	September 30, 2020		December 31, 2019
GCF	$	40.1	$	39.2
Cedar Cove JV	1.8		3.9
Total investment in unconsolidated affiliates	$	41.9	$	43.1

21

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(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 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 and the Managing Member 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Cost of unit-based compensation charged to operating expense	$	2.0	$	2.1	$	6.2	$	4.5
Cost of unit-based compensation charged to general and administrative expense	6.4		10.0		18.4		26.7
Total unit-based compensation expense	$	8.4	$	12.1	$	24.6	$	31.2
Non-controlling interest in unit-based compensation	$	—	$	—	$	—	$	0.5
Amount of related income tax benefit recognized in net income (loss) (1)	$	2.0	$	2.8	$	5.8	$	7.2

____________________________

(1)For the three and nine months ended September 30, 2020, the amount of related income tax expense recognized in net income (loss) excluded $1.6 million and $6.0 million, respectively, related to book-to-tax differences recorded upon vesting of restricted units. For the three and nine months ended September 30, 2019, the amount of related income tax expense recognized in net income excluded $1.3 million for each period related to book-to-tax differences recorded upon vesting of restricted units.

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 nine months ended September 30, 2020 is provided below:

	Nine Months Ended September 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)	4,873,848		5.42
Vested (1)(2)	(2,839,869)		10.93
Forfeited	(661,623)		8.28
Non-vested, end of period	5,435,961		$	8.50
Aggregate intrinsic value, end of period (in millions)	$	12.8

____________________________

(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 1,009,546 units withheld for payroll taxes paid on behalf of employees.

22

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 nine months ended September 30, 2020 and 2019 is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Restricted Incentive Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	1.0	$	3.1	$	11.9	$	16.0
Fair value of units vested	$	6.0	$	5.8	$	31.0	$	18.9

As of September 30, 2020, there was $23.3 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 1.6 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:

	Nine Months Ended September 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	1,361,986		6.63
Vested (1)	(181,647)		30.31
Forfeited	(166,211)		11.01
Non-vested, end of period	2,331,984		$	8.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

____________________________

(1)Vested units included 69,052 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 nine months ended September 30, 2020 and 2019 is provided below (in millions).

	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Performance Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	—	$	1.6	$	0.9	$	3.4
Fair value of units vested	$	—	$	6.0	$	5.5	$	7.9

As of September 30, 2020, there was $12.3 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 1.5 years.

23

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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			July 2020
Grant-Date Fair Value	$	7.69		$	1.13		$	2.33
Beginning TSR price	$	6.13		$	1.25		$	2.52
Risk-free interest rate	1.62		%	0.42		%	0.17		%
Volatility factor	37.00		%	51.00		%	67.00		%

(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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of interest rate swap	$	4.7	$	(1.8)	$	(10.4)	$	(15.3)
Tax benefit (expense)	(1.1)		0.5		2.4		4.1
Gain (loss) on designated cash flow hedge	$	3.6	$	(1.3)	$	(8.0)	$	(11.2)

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Interest expense (income)	$	4.6	$	(0.1)	$	9.6	$	(0.4)

We expect to recognize an additional $18.6 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

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

	September 30, 2020		December 31, 2019
Fair value of derivative liabilities—current	$	(18.5)	$	(5.6)
Fair value of derivative liabilities—long-term	(4.5)		(6.8)
Net fair value of interest rate swaps	$	(23.0)	$	(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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of derivatives	$	(2.2)	$	(0.5)	$	(8.0)	$	4.7
Realized gain (loss) on derivatives	(2.9)		8.0		(0.3)		11.5
Gain (loss) on derivative activity	$	(5.1)	$	7.5	$	(8.3)	$	16.2

24

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

	September 30, 2020		December 31, 2019
Fair value of derivative assets—current	$	9.6	$	12.9
Fair value of derivative assets—long-term	5.4		4.3
Fair value of derivative liabilities—current	(14.6)		(8.8)
Net fair value of commodity swaps	$	0.4	$	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 September 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022.

		September 30, 2020
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gallons	(161.6)	$	(8.5)
NGL (long contracts)	Swaps	Gallons	1.9	—
Natural gas (short contracts)	Swaps	MMBtu	(18.1)	(2.3)
Natural gas (long contracts)	Swaps	MMBtu	11.3	0.5
Crude and condensate (short contracts)	Swaps	MMbbls	(9.5)	8.5
Crude and condensate (long contracts)	Swaps	MMbbls	0.6	2.2
Total fair value of commodity swaps				$	0.4

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 $15.0 million as of September 30, 2020 would be reduced to $9.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

(12) Fair Value Measurements

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

	Level 2
	September 30, 2020		December 31, 2019
Interest rate swaps (1)	$	(23.0)	$	(12.4)
Commodity swaps (2)	$	0.4	$	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.

25

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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):

	September 30, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,650.0	$	3,892.8	$	4,764.3	$	4,444.2

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance costs of $26.4 million and $29.8 million as of September 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 September 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;

•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;

•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;

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

26

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(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		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2020
Natural gas sales	$	46.5	$	76.4	$	40.1	$	16.0	$	—	$	179.0
NGL sales	0.1		402.3		1.2		—		—		403.6
Crude oil and condensate sales	82.6		21.7		9.2		—		—		113.5
Product sales	129.2		500.4		50.5		16.0		—		696.1
NGL sales—related parties	95.6		3.3		85.4		21.4		(205.7)		—
Crude oil and condensate sales—related parties	—		—		—		0.7		(0.7)		—
Product sales—related parties	95.6		3.3		85.4		22.1		(206.4)		—
Gathering and transportation	17.9		10.7		56.7		43.4		—		128.7
Processing	8.0		0.3		32.4		33.3		—		74.0
NGL services	—		14.2		—		—		—		14.2
Crude services	3.8		12.2		3.7		—		—		19.7
Other services	0.2		0.4		0.1		0.2		—		0.9
Midstream services	29.9		37.8		92.9		76.9		—		237.5
Crude services—related parties	—		—		0.1		—		(0.1)		—
Midstream services—related parties	—		—		0.1		—		(0.1)		—
Revenue from contracts with customers	254.7		541.5		228.9		115.0		(206.5)		933.6
Cost of sales	(185.4)		(441.4)		(101.0)		(28.2)		206.5		(549.5)
Operating expenses	(22.9)		(31.1)		(20.1)		(20.2)		—		(94.3)
Loss on derivative activity	—		—		—		—		(5.1)		(5.1)
Segment profit (loss)	$	46.4	$	69.0	$	107.8	$	66.6	$	(5.1)	$	284.7
Depreciation and amortization	$	(31.9)	$	(36.9)	$	(53.0)	$	(36.8)	$	(1.7)	$	(160.3)
Capital expenditures	$	28.5	$	8.5	$	2.6	$	3.0	$	0.6	$	43.2

27

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2019
Natural gas sales	$	24.3	$	92.0	$	54.6	$	22.2	$	—	$	193.1
NGL sales	0.3		421.0		4.6		6.0		—		431.9
Crude oil and condensate sales	409.4		74.6		28.2		—		—		512.2
Product sales	434.0		587.6		87.4		28.2		—		1,137.2
Natural gas sales—related parties	(0.1)		—		—		—		0.1		—
NGL sales—related parties	69.3		7.9		90.2		21.0		(188.4)		—
Crude oil and condensate sales—related parties	2.8		1.7		—		1.1		(5.6)		—
Product sales—related parties	72.0		9.6		90.2		22.1		(193.9)		—
Gathering and transportation	14.7		12.2		63.7		50.1		—		140.7
Processing	8.3		0.8		35.7		36.3		—		81.1
NGL services	—		11.2		—		—		—		11.2
Crude services	6.4		13.5		5.9		—		—		25.8
Other services	4.0		0.1		0.1		0.3		—		4.5
Midstream services	33.4		37.8		105.4		86.7		—		263.3
Crude services—related parties	—		—		0.2		—		(0.2)		—
Midstream services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	539.4		635.0		283.2		137.0		(194.1)		1,400.5
Cost of sales	(474.2)		(529.6)		(148.4)		(41.4)		194.1		(999.5)
Operating expenses	(28.9)		(38.4)		(25.7)		(26.2)		—		(119.2)
Gain on derivative activity	—		—		—		—		7.5		7.5
Segment profit	$	36.3	$	67.0	$	109.1	$	69.4	$	7.5	$	289.3
Depreciation and amortization	$	(31.6)	$	(37.3)	$	(51.1)	$	(35.4)	$	(1.9)	$	(157.3)
Goodwill	$	184.6	$	—	$	813.4	$	125.7	$	—	$	1,123.7
Capital expenditures	$	119.7	$	21.5	$	48.6	$	5.0	$	1.7	$	196.5

28

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2020
Natural gas sales	$	94.0	$	226.6	$	110.0	$	50.7	$	—	$	481.3
NGL sales	0.2		1,056.9		2.9		0.3		—		1,060.3
Crude oil and condensate sales	454.6		95.0		30.4		—		—		580.0
Product sales	548.8		1,378.5		143.3		51.0		—		2,121.6
NGL sales—related parties	201.0		13.3		209.0		52.5		(475.8)		—
Crude oil and condensate sales—related parties	0.1		—		(0.1)		2.6		(2.6)		—
Product sales—related parties	201.1		13.3		208.9		55.1		(478.4)		—
Gathering and transportation	47.3		33.9		165.5		133.5		—		380.2
Processing	19.8		1.6		97.8		101.7		—		220.9
NGL services	—		52.4		—		0.1		—		52.5
Crude services	13.0		33.8		12.6		—		—		59.4
Other services	1.0		1.2		0.3		0.7		—		3.2
Midstream services	81.1		122.9		276.2		236.0		—		716.2
Crude services—related parties	—		—		0.3		—		(0.3)		—
Midstream services—related parties	—		—		0.3		—		(0.3)		—
Revenue from contracts with customers	831.0		1,514.7		628.7		342.1		(478.7)		2,837.8
Cost of sales	(637.7)		(1,213.6)		(255.8)		(74.1)		478.7		(1,702.5)
Operating expenses	(71.1)		(90.4)		(62.4)		(59.2)		—		(283.1)
Loss on derivative activity	—		—		—		—		(8.3)		(8.3)
Segment profit (loss)	$	122.2	$	210.7	$	310.5	$	208.8	$	(8.3)	$	843.9
Depreciation and amortization	$	(92.1)	$	(109.3)	$	(163.7)	$	(110.4)	$	(5.8)	$	(481.3)
Impairments	$	(184.6)	$	(169.9)	$	—	$	—	$	—	$	(354.5)
Capital expenditures	$	161.4	$	39.3	$	14.1	$	10.7	$	1.7	$	227.2

29

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2019
Natural gas sales	$	59.4	$	316.8	$	176.5	$	104.7	$	—	$	657.4
NGL sales	0.9		1,492.9		17.8		24.0		—		1,535.6
Crude oil and condensate sales	1,622.2		216.9		86.4		—		—		1,925.5
Product sales	1,682.5		2,026.6		280.7		128.7		—		4,118.5
Natural gas sales—related parties	0.3		—		—		0.3		(0.6)		—
NGL sales—related parties	242.9		16.4		320.9		71.7		(651.9)		—
Crude oil and condensate sales—related parties	13.7		1.7		—		3.8		(19.2)		—
Product sales—related parties	256.9		18.1		320.9		75.8		(671.7)		—
Gathering and transportation	36.3		46.1		178.2		149.0		—		409.6
Processing	23.3		2.5		105.5		106.8		—		238.1
NGL services	—		32.9		—		—		—		32.9
Crude services	16.9		40.2		15.1		—		—		72.2
Other services	8.4		0.5		—		0.8		—		9.7
Midstream services	84.9		122.2		298.8		256.6		—		762.5
NGL services—related parties	—		(3.3)		—		—		3.3		—
Crude services—related parties	—		—		1.7		—		(1.7)		—
Midstream services—related parties	—		(3.3)		1.7		—		1.6		—
Revenue from contracts with customers	2,024.3		2,163.6		902.1		461.1		(670.1)		4,881.0
Cost of sales	(1,830.9)		(1,844.1)		(492.0)		(166.1)		670.1		(3,663.0)
Operating expenses	(85.1)		(111.6)		(77.2)		(77.7)		—		(351.6)
Gain on derivative activity	—		—		—		—		16.2		16.2
Segment profit	$	108.3	$	207.9	$	332.9	$	217.3	$	16.2	$	882.6
Depreciation and amortization	$	(89.6)	$	(116.0)	$	(144.8)	$	(106.6)	$	(6.1)	$	(463.1)
Impairments	$	—	$	(186.5)	$	—	$	—	$	—	$	(186.5)
Goodwill	$	184.6	$	—	$	813.4	$	125.7	$	—	$	1,123.7
Capital expenditures	$	268.0	$	82.0	$	227.1	$	36.3	$	5.7	$	619.1

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Segment profit	$	284.7	$	289.3	$	843.9	$	882.6
General and administrative expenses	(25.7)		(38.5)		(79.6)		(122.1)
Gain (loss) on disposition of assets	1.8		3.0		(2.8)		2.9
Depreciation and amortization	(160.3)		(157.3)		(481.3)		(463.1)
Impairments	—		—		(354.5)		(186.5)
Loss on secured term loan receivable	—		—		—		(52.9)
Operating income (loss)	$	100.5	$	96.5	$	(74.3)	$	60.9

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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 September 30, 2020 and December 31, 2019 (in millions):

Segment Identifiable Assets:	September 30, 2020		December 31, 2019
Permian	$	2,245.3	$	2,465.7
Louisiana	2,278.9		2,562.0
Oklahoma	2,889.1		3,035.0
North Texas	1,031.2		1,135.8
Corporate	222.7		137.3
Total identifiable assets	$	8,667.2	$	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:	September 30, 2020		December 31, 2019
Natural gas and NGLs inventory	$	63.9	$	43.4
Prepaid expenses and other	17.8		14.4
Other current assets	$	81.7	$	57.8

Other current liabilities:	September 30, 2020		December 31, 2019
Accrued interest	$	66.7	$	37.1
Accrued wages and benefits, including taxes	18.3		31.5
Accrued ad valorem taxes	33.9		28.5
Capital expenditure accruals	12.1		42.4
Retainage liability	11.8		8.7
Short-term lease liability	17.1		21.1
Suspense producer payments	10.3		13.8
Operating expense accruals	10.5		10.8
Other	18.1		12.3
Other current liabilities	$	198.8	$	206.2

(15) Subsequent Events

Accounts Receivable Securitization Facility. On October 21, 2020 (the “Closing Date”), EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity (the “SPV”) that is an indirect subsidiary of ENLC entered into a three-year committed accounts receivable securitization facility (the “AR Facility”) of up to $250 million with PNC Bank, National Association, as administrative agent (the “Administrative Agent”) and lender, and PNC Capital Markets, LLC (“PNCCM”), as structuring agent.

In connection with the AR Facility, certain subsidiaries of ENLC, as originators (the “Originators”), have sold and contributed, and will continue to sell or contribute, pursuant to a Sale and Contribution Agreement, dated as of the Closing Date (the “Sale and Contribution Agreement”), all of their accounts receivable and certain related assets (collectively, the “Receivables”) to the SPV, a separate legal subsidiary of ENLC whose sole business consists of the purchase, or acceptance through capital contributions, of the Receivables and whose assets are not available to satisfy creditors of ENLC, the Originators, or any other subsidiary of ENLC.

The SPV financed its acquisition of the Receivables, and will finance its ongoing purchase of the Receivables, in part by obtaining secured loans from the lenders party to the Receivables Financing Agreement, dated as of the Closing Date (the “RFA”), among the SPV, EnLink Midstream Operating, LP, as initial servicer (the “Servicer”), the Administrative Agent, the lenders party thereto, and PNCCM. The amount available for borrowings at any one time under the RFA is limited to a borrowing base amount calculated based on the outstanding balance of eligible Receivables, subject to certain reserves,

31

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

concentration limits, and other limitations. Borrowings under the RFA bear interest based on LIBOR or LMIR (each as defined in the RFA), in each case subject to a minimum floor of 37.5 basis points, plus a drawn fee initially in the amount of 162.5 bps. The drawn fee varies based on ENLC’s credit rating, and the SPV also pays a fee on the undrawn committed amount of the RFA. Interest and fees payable by the SPV under the RFA are due monthly.

The SPV pledged its ownership interest in the Receivables as collateral security for all amounts outstanding under the RFA, and the Servicer will perform administrative and collection services relating to the Receivables on behalf of the SPV for a fee.

The RFA is scheduled to terminate on October 20, 2023, unless extended in accordance with its terms or earlier terminated, at which time no further advances will be available and the obligations thereunder repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the RFA become due and payable.

The purchase price for the sale of the Receivables by an Originator to the SPV consisted of, and will continue to consist of, a combination of (i) equity contributions in the SPV from its direct parent, (ii) cash available to the SPV from loans under the RFA and from collections on previously sold Receivables, and (iii) to the extent that the SPV does not have funds available to pay the purchase price in cash, through an increase in the principal amount of a subordinated intercompany loan deemed made by such Originator to the SPV.

ENLC guaranteed the respective obligations of the Originators and the Servicer under the Sale and Contribution Agreement and the RFA, as applicable, pursuant to a Performance Guaranty dated as of the Closing Date. However, neither ENLC nor any of its subsidiaries guarantees the SPV’s borrowings under the RFA or the collectability of the Receivables.

As of the Closing Date there were $225 million of borrowings by the SPV under the RFA. ENLC used the cash proceeds from the sale of the Receivables to the SPV to repay borrowings under its revolving credit facility.

Sale of Victoria Express Pipeline. On October 22, 2020, we completed the sale of the Victoria Express Pipeline and its related terminals and storage assets located in the Eagle Ford Shale in South Texas for approximately $20 million. We expect to recognize a loss of approximately $8 million on the sale.

Common Unit Repurchase Program. The board of directors of the Managing Member has authorized, effective immediately, a common unit repurchase program for the repurchase of up to $100 million of outstanding ENLC common units. The repurchases will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The repurchases will depend on market conditions and may be discontinued at any time.

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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.

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.

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 11,800 miles of pipelines, 22 natural gas processing plants with approximately 5.5 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:

•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;

•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;

•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;

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

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 95% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the nine months ended September 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Devon	14.2	%	11.7	%	14.7	%	10.0	%
Dow Hydrocarbons and Resources LLC	15.2	%	(1)		13.2	%	10.0	%
Marathon Petroleum Corporation	(1)		12.4	%	12.7	%	14.0	%

____________________________

(1)Consolidated revenues for these customers did not exceed 10% of our consolidated revenues for the applicable reporting period.

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

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 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 energy, volatility in the market prices for these commodities, and a significant and persistent reduction in the market price of crude oil. As a result of the demand destruction, reduced commodity prices, and an uncertain timeline for full recovery, many oil and natural gas producers, including some of our customers, have curtailed their current drilling and production activity and reduced or slowed down their plans for future drilling and production activity. As a result of these decreases in producer activity, we experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems during portions of the first and second quarters, although volumes have since been restored nearly to pre-pandemic levels.

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. In March, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations, and we continue to follow these plans. We maintain a crisis management team for health, safety and environmental matters and personnel issues and a cross-functional COVID-19 response team to address various impacts of the situation, as they develop. We also continue to follow modified business practices (including discontinuing non-essential business travel, implementing staggered work-from-home policies for employees who can execute their work remotely in order to reduce office density, 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.

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 whether 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 that exist as of the date of this report will be extended or new measures will be reinstated. As a result, there is significant uncertainty regarding whether market dislocations will continue or increase and how significantly and how long they may 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).

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 throughout the period. 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

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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 September 30, 2020, we had $78.9 million of cash on our balance sheet and have drawn only $300.0 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 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, 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 2020, we completed the construction of our Tiger Plant, which expanded our Delaware Basin processing capacity by an additional 200 MMcf/d. 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”), free cash flow after distributions, 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.

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

36

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net income (loss)	$	39.2	$	37.5	$	(191.4)	$	(88.2)
Interest expense, net of interest income	55.5		56.6		166.3		160.5
Depreciation and amortization	160.3		157.3		481.3		463.1
Impairments	—		—		354.5		186.5
Loss on secured term loan receivable (1)	—		—		—		52.9
(Income) loss from unconsolidated affiliates	0.2		(4.0)		(0.8)		(14.0)
Distributions from unconsolidated affiliates	—		5.4		2.0		15.5
(Gain) loss on disposition of assets	(1.8)		(3.0)		2.8		(2.9)
Gain on extinguishment of debt	—		—		(32.0)		—
Unit-based compensation	8.4		12.1		24.6		31.2
Income tax expense (benefit)	6.0		6.3		(16.0)		2.7
Unrealized (gain) loss on commodity swaps	2.2		0.5		8.0		(4.7)
Payments under onerous performance obligation offset to other current and long-term liabilities	—		—		—		(9.0)
Transaction costs (2)	—		—		—		13.9
Other (3)	(0.3)		(1.2)		(0.8)		(0.8)
Adjusted EBITDA before non-controlling interest	269.7		267.5		798.5		806.7
Non-controlling interest share of adjusted EBITDA from joint ventures (4)	(8.1)		(6.3)		(21.8)		(18.1)
Adjusted EBITDA, net to ENLC	$	261.6	$	261.2	$	776.7	$	788.6

____________________________

(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 nine months ended September 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.

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Distributable Cash Flow and Free Cash Flow After Distributions

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. Free cash flow after distributions 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 free cash flow after distributions 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 free cash flow after distributions is net cash provided by operating activities. Distributable cash flow and free cash flow after distributions 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 free cash flow after distributions 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 free cash flow after distributions 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 free cash flow after distributions, to evaluate our overall liquidity.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net cash provided by operating activities	$	244.2	$	256.0	$	561.0	$	777.5
Interest expense (1)	54.6		55.8		163.3		159.2
Current income tax expense	0.4		0.7		1.1		2.0
Transaction costs (2)	—		—		—		13.9
Other (3)	0.4		(1.6)		0.9		(1.5)
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	46.5		(78.0)		(72.6)		(341.3)
Accounts payable, accrued product purchases, and other accrued liabilities (4)	(76.4)		34.6		144.8		196.9
Adjusted EBITDA before non-controlling interest	269.7		267.5		798.5		806.7
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(8.1)		(6.3)		(21.8)		(18.1)
Adjusted EBITDA, net to ENLC	261.6		261.2		776.7		788.6
Interest expense, net of interest income	(55.5)		(56.6)		(166.3)		(160.5)
Maintenance capital expenditures, net to ENLC (6)	(5.0)		(12.7)		(20.9)		(34.4)
ENLK preferred unit accrued cash distributions (7)	(22.9)		(23.1)		(68.5)		(68.9)
Other (8)	(0.5)		(0.6)		(1.1)		(4.1)
Distributable cash flow	177.7		168.2		519.9		520.7
Common distributions declared	(46.4)		(139.2)		(139.3)		(415.8)
Growth capital expenditures, net to ENLC (6)	(32.6)		(149.4)		(165.9)		(510.9)
Free cash flow after distributions	$	98.7	$	(120.4)	$	214.7	$	(406.0)

____________________________

(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 nine months ended September 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating income (loss)	$	100.5	$	96.5	$	(74.3)	$	60.9
Add:
Operating expenses	94.3		119.2		283.1		351.6
General and administrative expenses	25.7		38.5		79.6		122.1
(Gain) loss on disposition of assets	(1.8)		(3.0)		2.8		(2.9)
Depreciation and amortization	160.3		157.3		481.3		463.1
Impairments	—		—		354.5		186.5
Loss on secured term loan receivable	—		—		—		52.9
Gross operating margin	$	379.0	$	408.5	$	1,127.0	$	1,234.2

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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Permian Segment
Revenues	$	254.7	$	539.4	$	831.0	$	2,024.3
Cost of sales	(185.4)		(474.2)		(637.7)		(1,830.9)
Total gross operating margin	$	69.3	$	65.2	$	193.3	$	193.4
Louisiana Segment
Revenues	$	541.5	$	635.0	$	1,514.7	$	2,163.6
Cost of sales	(441.4)		(529.6)		(1,213.6)		(1,844.1)
Total gross operating margin	$	100.1	$	105.4	$	301.1	$	319.5
Oklahoma Segment
Revenues	$	228.9	$	283.2	$	628.7	$	902.1
Cost of sales	(101.0)		(148.4)		(255.8)		(492.0)
Total gross operating margin	$	127.9	$	134.8	$	372.9	$	410.1
North Texas Segment
Revenues	$	115.0	$	137.0	$	342.1	$	461.1
Cost of sales	(28.2)		(41.4)		(74.1)		(166.1)
Total gross operating margin	$	86.8	$	95.6	$	268.0	$	295.0
Corporate Segment
Revenues	$	(211.6)	$	(186.6)	$	(487.0)	$	(653.9)
Cost of sales	206.5		194.1		478.7		670.1
Total gross operating margin	$	(5.1)	$	7.5	$	(8.3)	$	16.2
Total
Revenues	$	928.5	$	1,408.0	$	2,829.5	$	4,897.2
Cost of sales	(549.5)		(999.5)		(1,702.5)		(3,663.0)
Total gross operating margin	$	379.0	$	408.5	$	1,127.0	$	1,234.2
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d)	923,400		751,400		875,200		695,300
Processing (MMBtu/d)	929,900		798,200		895,800		745,100
Crude Oil Handling (Bbls/d)	99,100		112,900		115,000		135,000
Louisiana Segment
Gathering and Transportation (MMBtu/d)	1,961,100		2,078,500		1,959,600		2,025,000
Crude Oil Handling (Bbls/d)	15,700		21,200		16,300		18,800
NGL Fractionation (Gals/d)	7,462,600		7,240,100		7,665,700		7,231,400
Brine Disposal (Bbls/d)	1,100		2,500		1,400		3,100
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	1,113,900		1,351,800		1,142,800		1,304,100
Processing (MMBtu/d)	1,125,600		1,323,100		1,120,800		1,284,800
Crude Oil Handling (Bbls/d)	25,600		59,600		30,800		47,600
North Texas Segment
Gathering and Transportation (MMBtu/d)	1,450,900		1,644,300		1,505,100		1,658,000
Processing (MMBtu/d)	669,000		760,700		679,800		753,600

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

Gross Operating Margin. Gross operating margin was $379.0 million for the three months ended September 30, 2020 compared to $408.5 million for the three months ended September 30, 2019, a decrease of $29.5 million, or 7.2%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment increased $4.1 million, resulting from:

•A $2.7 million decrease on our South Texas assets primarily due to the expiration of an MVC provision in July 2019.

•A $3.4 million decrease due to volume declines on our Midland Basin crude assets.

•A $1.3 million increase due to volume growth in our Delaware Basin crude assets.

•A $6.0 million increase related to volume growth from additional well connects on our Midland Basin gas assets.

•A $2.9 million increase related to volume growth from additional well connects on our Delaware Basin gas assets.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $5.3 million, resulting from:

•A $7.0 million decrease from our ORV crude assets primarily due to lower volumes.

•A $1.7 million increase from our NGL transmission and fractionation assets primarily due to higher volumes.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $6.9 million, resulting from:

•A $3.8 million decrease due to volume decline in our Oklahoma crude assets primarily due to lower volumes from our existing customers.

•A $3.1 million decrease due to volume decline in our Oklahoma gas assets primarily due to lower volumes from our existing customers.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $8.8 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $12.6 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 September 30,
	2020		2019
Realized swaps:
Crude swaps	$	0.2	$	5.5
NGL swaps	(3.4)		1.8
Gas swaps	0.3		0.7
Realized gain (loss) on derivatives	(2.9)		8.0
Unrealized swaps:
Crude swaps	1.4		(0.4)
NGL swaps	(2.5)		(0.4)
Gas swaps	(1.1)		0.3
Change in fair value of derivatives	(2.2)		(0.5)
Gain (loss) on derivatives	$	(5.1)	$	7.5

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

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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.

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

	Three Months Ended September 30,
	2020		2019
Permian Segment	$	0.3	$	1.7
Oklahoma Segment	13.7		4.8
Total	$	14.0	$	6.5

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 $94.3 million for the three months ended September 30, 2020 compared to $119.2 million for the three months ended September 30, 2019, a decrease of $24.9 million, or 20.9%. The primary contributors to the total decrease by segment were as follows (in millions):

	Three Months Ended September 30,				Change
	2020		2019		$		%
Permian Segment	$	22.9	$	28.9	$	(6.0)	(20.8)	%
Louisiana Segment	31.1		38.4		(7.3)		(19.0)	%
Oklahoma Segment	20.1		25.7		(5.6)		(21.8)	%
North Texas Segment	20.2		26.2		(6.0)		(22.9)	%
Total	$	94.3	$	119.2	$	(24.9)	(20.9)	%

•Permian Segment. Operating expenses in the Permian segment decreased $6.0 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in construction fees and services.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $7.3 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, and vehicle expenses.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $5.6 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in construction fees and services and compressor rentals.

•North Texas Segment. Operating expenses in the North Texas segment decreased $6.0 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, compression operations and maintenance, and compressor rentals.

General and Administrative Expenses. General and administrative expenses were $25.7 million for the three months ended September 30, 2020 compared to $38.5 million for the three months ended September 30, 2019, a decrease of $12.8 million, or 33.2%. The primary contributors to the decrease were as follows:

•Labor costs and unit-based compensation costs decreased $10.8 million, which was primarily due to reductions in workforce.

•Expenses related to fees and services, travel, rents and leases, and insurance decreased $1.7 million primarily due to general cost saving initiatives and decreased activity as a result of COVID-19.

Depreciation and Amortization. Depreciation and amortization was $160.3 million for the three months ended September 30, 2020 compared to $157.3 million for the three months ended September 30, 2019, an increase of $3.0 million, or 1.9%. This increase was primarily due to new assets placed in service in the Permian, Oklahoma, and Louisiana segments, as

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well as a change in the estimated useful lives of certain non-core assets in the North Texas and Oklahoma segments. 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.

Gain (loss) on disposition of assets. For the three months ended September 30, 2020, we recognized a gain on the sale of assets of $1.8 million compared to a gain of $3.0 million for the three months ended September 30, 2019. The $1.8 million gain was primarily related to the sale of non-core assets in North Texas.

Interest Expense. Interest expense was $55.5 million for the three months ended September 30, 2020 compared to $56.6 million for the three months ended September 30, 2019, a decrease of $1.1 million, or 1.9%. Interest expense consisted of the following (in millions):

	Three Months Ended September 30,
	2020		2019
ENLK and ENLC Senior Notes	$	43.3	$	44.0
Term Loan	3.6		8.0
Consolidated Credit Facility	3.4		3.8
Capitalized interest	(0.6)		(0.3)
Amortization of debt issue costs and net discounts (premiums)	0.9		1.1
Interest rate swap - realized	4.6		(0.1)
Other	0.3		0.1
Total	$	55.5	$	56.6

Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $0.2 million for the three months ended September 30, 2020 compared to income of $4.0 million for the three months ended September 30, 2019, a decrease of $4.2 million. The decrease was primarily attributable to a reduction of income of $4.0 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 expense was $6.0 million for the three months ended September 30, 2020 compared to an income tax expense of $6.3 million for the three months ended September 30, 2019 on comparable income amounts. See “Item 1. Financial Statements—Note 6” for additional information.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Gross Operating Margin. Gross operating margin was $1,127.0 million for the nine months ended September 30, 2020 compared to $1,234.2 million for the nine months ended September 30, 2019, a decrease of $107.2 million, or 8.7%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment decreased $0.1 million, primarily driven by:

•A $14.3 million decrease on our South Texas assets primarily due to the expiration of an MVC provision in July 2019.

•A $4.2 million increase due to volume growth in our Delaware Basin crude assets.

•A $4.1 million increase related to volume growth from additional well connects on our Midland Basin gas assets.

•A $5.6 million increase related to volume growth from additional well connects on our Delaware Basin gas assets.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $18.4 million, resulting from:

•A $12.4 million decrease from our Louisiana gas assets due to the expiration of certain firm transportation contracts, and decreased gathering and transportation volumes.

•A $13.1 million decrease from our ORV crude assets primarily due to lower volumes.

•A $7.1 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 in the amount of $5.5 million.

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•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $37.2 million, resulting from:

•A $2.9 million decrease due to volume decline in our Oklahoma crude assets primarily due to lower volumes from our existing customers..

•A $34.3 million decrease due to volume decline in our Oklahoma gas assets primarily due to lower volumes from our existing customers.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $27.0 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $24.5 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):

	Nine Months Ended September 30,
	2020		2019
Realized swaps:
Crude swaps	$	(2.8)	$	6.4
NGL swaps	2.9		7.4
Gas swaps	(0.4)		(2.3)
Realized gain (loss) on derivatives	(0.3)		11.5
Unrealized swaps:
Crude swaps	3.9		4.1
NGL swaps	(9.5)		(2.7)
Gas swaps	(2.4)		3.3
Change in fair value of derivatives	(8.0)		4.7
Gain (loss) on derivatives	$	(8.3)	$	16.2

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.

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

	Nine Months Ended September 30,
	2020		2019
Permian	$	0.6	$	9.4
Oklahoma	38.6		4.8
Total	$	39.2	$	14.2

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.

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Operating Expenses. Operating expenses were $283.1 million for the nine months ended September 30, 2020 compared to $351.6 million for the nine months ended September 30, 2019, a decrease of $68.5 million, or 19.5%. The primary contributors to the decrease by segment were as follows (in millions):

	Nine Months Ended September 30,				Change
	2020		2019		$		%
Permian Segment	$	71.1	$	85.1	$	(14.0)	(16.5)	%
Louisiana Segment	90.4		111.6		(21.2)		(19.0)	%
Oklahoma Segment	62.4		77.2		(14.8)		(19.2)	%
North Texas Segment	59.2		77.7		(18.5)		(23.8)	%
Total	$	283.1	$	351.6	$	(68.5)	(19.5)	%

•Permian Segment. Operating expenses in the Permian segment decreased $14.0 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, vehicle expenses, and sales and use tax.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $21.2 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, compressor rentals, and vehicle expenses.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $14.8 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, compressor rentals, and vehicle expenses.

•North Texas Segment. Operating expenses in the North Texas segment decreased $18.5 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, operations and maintenance, fees and services, sales and use tax, ad valorem taxes, and compressor rentals.

General and Administrative Expenses. General and administrative expenses were $79.6 million for the nine months ended September 30, 2020 compared to $122.1 million for the nine months ended September 30, 2019, a decrease of $42.5 million, or 34.8%. 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 $19.6 million due to reductions in workforce and lower bonus accrual.

•Expenses related to fees and services, travel, rents and leases, and insurance decreased $6.8 million, which was primarily due to general cost saving initiatives.

Depreciation and Amortization. Depreciation and amortization was $481.3 million for the nine months ended September 30, 2020 compared to $463.1 million for the nine months ended September 30, 2019, an increase of $18.2 million, or 3.9%. This increase was primarily due to new assets placed in service in the Permian and Oklahoma segments, as well as a change in the estimated useful lives of certain non-core assets in the North Texas and Oklahoma segments. 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.

Gain (loss) on disposition of assets. For the nine months ended September 30, 2020, we recognized a loss on the sale of assets of $2.8 million compared to a gain of $2.9 million for the nine months ended September 30, 2019. The $2.8 million loss was primarily related to the sale of non-core Permian assets, partially offset by the sale of certain non-core assets in North Texas.

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Impairments. For the nine months ended September 30, 2020, we recognized impairment expense related to goodwill and property and equipment. For the nine months ended September 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):

	Nine Months Ended September 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 nine months ended September 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 nine months ended September 30, 2019 related to the write-off of the secured term loan receivable.

Interest Expense. Interest expense was $166.3 million for the nine months ended September 30, 2020 compared to $160.5 million for the nine months ended September 30, 2019, an increase of $5.8 million, or 3.6%. Interest expense consisted of the following (in millions):

	Nine Months Ended September 30,
	2020		2019
ENLK and ENLC Senior Notes	$	130.6	$	127.9
Term Loan	14.2		25.1
Consolidated Credit Facility	11.6		9.9
Capitalized interest	(3.1)		(4.1)
Amortization of debt issue costs and net discounts (premiums)	3.1		3.9
Interest rate swap - realized	9.6		(0.4)
Other	0.3		(1.8)
Total	$	166.3	$	160.5

Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $0.8 million for the nine months ended September 30, 2020 compared to $14.0 million for the nine months ended September 30, 2019, a decrease of $13.2 million. The decrease was primarily attributable to a reduction of income of $12.8 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of $0.4 million from our Cedar Cove JV.

Income Tax Expense. Income tax benefit was $16.0 million for the nine months ended September 30, 2020 compared to an income tax expense of $2.7 million for the nine months ended September 30, 2019. The increase in income tax benefit was primarily attributable to lower income between periods and tax deficiencies recorded upon the vesting of restricted incentive units. 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 $78.7 million for the nine months ended September 30, 2020 compared to net income of $92.4 million for the nine months ended September 30, 2019, a decrease of $13.7 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 nine months ended September 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. For the three months ended September 30, 2020, we did not recognize any impairment related to property and equipment.

In the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets and investments, which could result in further impairment charges. See “Item 1. Financial Statements—Note 1” for additional information.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $561.0 million for the nine months ended September 30, 2020 compared to $777.5 million for the nine months ended September 30, 2019. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

	Nine Months Ended September 30,
	2020		2019
Operating cash flows before working capital	$	633.2	$	642.1
Changes in working capital	(72.2)		135.4

Operating cash flows before changes in working capital decreased $8.9 million for the nine months ended September 30, 2020 compared to the nine months ended September 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 $96.2 million.

•Distribution of earnings from unconsolidated affiliates decreased $13.1 million.

•Interest expense, excluding amortization of debt issue costs and net discounts (premium) of notes, increased $6.6 million.

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

•Operating expenses excluding unit-based compensation decreased $70.3 million primarily due to reductions in workforce. For more information, see “Results of Operations.”

•General and administrative expenses excluding unit-based compensation decreased $34.3 million primarily due to a reduction in costs across our platform, reductions in workforce, and transaction costs related to the Merger in 2019. For more information, see “Results of Operations.”

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The changes in working capital for the nine months ended September 30, 2020 compared to the nine months ended September 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 $250.7 million for the nine months ended September 30, 2020, compared to $583.0 million for the nine months ended September 30, 2019. Investing cash flows are primarily related to capital expenditures, which decreased from $594.5 million for the nine months ended September 30, 2019 to $254.4 million for the nine months ended September 30, 2020. The decrease was primarily due to reduced capital spending plans for 2020. Additionally, proceeds from the sale of assets decreased from $13.7 million for the nine months ended September 30, 2019 to $7.2 million for the nine months ended September 30, 2020 related to the sale of non-core assets for each period.

Cash Flows from Financing Activities. Net cash used in financing activities was $308.8 million for the nine months ended September 30, 2020 compared to $192.7 million for the nine months ended September 30, 2019. Our primary financing activities consisted of the following (in millions):

	Nine Months Ended September 30,
	2020		2019
Net borrowings (repayments) on the Consolidated Credit Facility	$	(50.0)	$	275.0
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)	52.2		78.6
Distribution to members	(186.2)		(328.0)
Distributions to ENLK common units held by public unitholders (2)	—		(104.8)
Distributions to Series B Preferred Unitholders (3)	(50.4)		(50.3)
Distributions to Series C Preferred Unitholders (3)	(12.0)		(12.0)
Distributions to joint venture partners (4)	(21.8)		(18.0)

____________________________

(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 $15 million to $55 million, which is net of approximately $5 million to $15 million from our joint venture partners. Our primary capital projects for the remainder of 2020 relate to the continued development of our existing systems through well connects and other small projects.

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 September 30, 2020.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 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	300.0		—		—		—		—		300.0		—
Interest payable on fixed long-term debt obligations	2,399.8		74.6		173.1		173.1		173.1		161.6		1,644.3
Operating lease obligations	126.8		5.5		19.4		13.4		10.2		9.5		68.8
Purchase obligations	4.1		4.1		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (1)	184.4		14.5		41.0		31.8		28.1		33.0		36.0
Inactive easement commitment (2)	10.0		—		—		10.0		—		—		—
Total contractual obligations	$	7,407.4	$	98.7	$	1,083.5	$	228.3	$	211.4	$	1,025.9	$	4,759.6

____________________________

(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 September 30, 2020, there was $300.0 million in outstanding borrowings under the Consolidated Credit Facility and $19.3 million in outstanding letters of credit.

In addition, as of September 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” and “Item 1. Financial Statements—Note 15” 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,”

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“plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking 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

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and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative 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 95% of our gross operating margin for the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2020, approximately 5% 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 September 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)
October 2020 - May 2021	Ethane	1,971 (MBbls)	$0.2031/gal	Index	$	(2.3)
October 2020 - July 2021	Propane	1,273 (MBbls)	Index	$0.5083/gal	(3.2)
October 2020 - July 2021	Normal butane	447 (MBbls)	Index	$0.5921/gal	(1.3)
October 2020 - January 2021	Natural gasoline	202 (MBbls)	Index	$0.8779/gal	(1.7)
October 2020 - October 2021	Natural gas	80,632 (MMBtu/d)	Index	$2.3700/MMBtu	(1.8)
October 2020 - January 2021	Crude and condensate	1,030 (MBbls)	Index	$40.41/Bbl	0.4
October 2020 - December 2022	Crude and condensate	9,062 (MBbls)	$1.824/Bbl	Index (2)	10.3
					$	0.4

____________________________

(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 September 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 $0.4 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 $9.3 million in the net fair value of these contracts as of September 30, 2020. 

Interest Rate Risk

We are exposed to interest rate risk on the Consolidated Credit Facility and the Term Loan. At September 30, 2020, we had $300.0 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 $3.0 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 September 30, 2020, the estimated fair value of the senior unsecured notes was approximately $2,742.8 million, based on the market prices of ENLK’s and our publicly traded debt at September 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 $166.6 million decrease in fair value of the senior unsecured notes at September 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 (September 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 September 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 September 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
July 1, 2020 to July 31, 2020	69,889	$	2.35	—	—
August 1, 2020 to August 31, 2020	87,203	2.45		—	—
September 1, 2020 to September 30, 2020	1,791	2.99		—	—
Total	158,883	$	2.41	—	—

____________________________

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

Item 5. Other Information

Disclosure Pursuant to Item 5.02 of Form 8-K – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On November 3, 2020, J. Philipp Rossbach, the Company’s current Chief Accounting Officer, was named as the Company’s principal accounting officer. Mr. Rossbach will replace Pablo G. Mercado as the principal accounting officer of ENLC. Mr. Mercado will continue to serve as ENLC’s Chief Financial Officer and principal financial officer.

Mr. Rossbach, 39, has served as Chief Accounting Officer of the Company since April 2020. Previously, Mr. Rossbach served in other accounting roles with the Company, including as Corporate Controller from March 2016 to March 2020, as Director – Operations Accounting from August 2014 to February 2016, and as Manager – General Accounting from 2013. Mr. Rossbach will continue working under his existing compensation arrangements.

Also on November 3, 2020, the Operating Partnership amended and restated the existing Change in Control Agreement (the “CIC Agreement”) with each of ENLC’s named executive officers other than the Chairman and Chief Executive Officer to increase the change in control benefit multiplier from two times the change in control benefit to two and a half times the change in control benefit. The change in control benefit in the CIC Agreement consists of (A) the officer’s then-current base salary and (B) any target bonus for the year that includes the date of termination. The change in control benefit multiplier in the CIC Agreement with the Company’s Chairman and Chief Executive Officer remains unchanged at three times the change in control benefit.

For more information on the terms of the CIC Agreement, see ENLC’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019, filed with the Securities and Exchange Commission on February 26, 2020.

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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).
10.1	—	Sale and Contribution Agreement, dated as of October 21, 2020, by and among EnLink Midstream Funding, LLC, EnLink Midstream Operating, LP, and the originators from time to time party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated October 21, 2020, filed with the Commission on October 22, 2020, file No. 001-36336).
10.2	—	Receivables Financing Agreement, dated as of October 21, 2020, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, PNC Bank, National Association, as administrative agent and lender, the lenders party thereto, and PNC Capital Markets, LLC, as structuring agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated October 21, 2020, filed with the Commission on October 22, 2020, file No. 001-36336).
10.3 ‡*	—	Form of EnLink Midstream Operating, LP Amended and Restated Change in Control Agreement.
31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	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 September 30, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, 2020 and 2019, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended September 30, 2020 and 2019, June 30, 2020 and 2019, and March 31, 2020 and 2019, (iv) Consolidated Statements of Cash Flows for the nine months ended September 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.

‡    As required by Item 15(a)(3), this Exhibit is identified as a compensatory benefit plan or arrangement.

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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/ J. PHILIPP ROSSBACH
		J. Philipp Rossbach
		Chief Accounting Officer
		(Principal Accounting Officer)
November 5, 2020

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EX-10.3

Exhibit 10.3

ENLINK MIDSTREAM OPERATING, LP [EMPLOYEE’S APPLICABLE VERSION] CHANGE IN CONTROL AGREEMENT

THIS [APPLICABLE VERSION] CHANGE IN CONTROL AGREEMENT (this “Agreement”) dated as of __________, 20__ (the “Effective Date”) is made by and between EnLink Midstream Operating, LP, a Delaware limited partnership (the “Company”) and _________________________, an individual (“Individual”).

W I T N E S S E T H:

WHEREAS, the Company and Individual desire to [amend and restate that certain Change in Control Agreement dated as of [ ] (the “Original Agreement”)]/[enter into a Change in Control arrangement] on the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements hereinafter set forth, Individual and the Company hereby agree as follows:

ARTICLE I

Definitions

1.1    Definitions. For purposes of this Agreement, except as otherwise expressly provided herein or unless the context otherwise requires, the following terms shall have the following respective meanings:

“Accounting Firm” shall have the meaning set forth in Section 2.4(b).

“Agreement” shall have the meaning set forth in the preamble hereto.

“Board” means the Board of Directors of ENLC Manager (or such other managing member of ENLC or such other applicable governing body of ENLC).

“Cause” means any one or more of the following: (i) a material violation by Individual of the Company’s Code of Business Conduct and Ethics or any trading or other policy applicable to employees of the Company (which may include, but is not limited to, matters specifically mentioned below in the definition of Cause); (ii) willful engagement in serious or material misconduct or illegal conduct by Individual; (iii) a failure by Individual to perform the duties assigned to him or her that continues following notice from the Company to Individual of such failure; (iv) Individual is formally charged, indicted or convicted of a felony or a misdemeanor involving moral turpitude; (v) Individual has engaged in acts or omissions constituting dishonesty, breach of fiduciary obligation, gross misconduct, gross negligence, intentional wrongdoing, or misfeasance; (vi) Individual has failed to comply with any valid, legal, and material directive of the Company or the Board; (vii) Individual has engaged in embezzlement, misappropriation, or fraud, whether or not related to Individual’s employment with the Company; (viii) a material breach by Individual of any material obligation under this Agreement or any other written agreement between Individual and the Company Group; or (ix) Individual has acted intentionally or in bad faith in a manner that results or could be reasonably expected to result in a material detriment to the assets, business, prospects or reputation of any member of the Company Group. Any act, or failure to act, based upon the express or implied authority given pursuant to a resolution duly adopted by the Board or upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by Individual in good faith and in the best interests of the Company Group. Individual will be considered to have been terminated for Cause if the Company determines in its sole good faith judgment that he or she engaged in an act prior to termination that constituted Cause, regardless of whether Individual terminated employment voluntarily or is terminated involuntarily, and regardless of whether Individual’s termination initially was considered to have been without Cause. The Company may place Individual on paid leave while it is determining whether there is a basis to terminate Individual’s employment for Cause, it being understood that, any such action by the Company will not constitute Good Reason.

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“Change in Control” means the occurrence of any one or more of the following on or after the Effective Date: (i) the consummation of any transaction (including a merger or consolidation), the result of which is that any Person (other than GIP) becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of fifty percent (50%) or more of the Voting Stock of ENLC or ENLC Manager, measured by voting power rather than number of shares, units, or the like; (ii) the sale, transfer, or other disposition of all or substantially all of the assets of ENLC and its Subsidiaries on an aggregate basis to any Person (other than one or more members of the Company Group); or (iii) the adoption of a plan relating to the liquidation or dissolution of ENLC. Notwithstanding the foregoing, to the extent any amounts hereunder are subject to Section 409A of the Code and such amounts are payable upon the occurrence of a Change in Control following a Qualifying Termination, no such payments shall be made unless such Change in Control qualifies as a “change in control event” within the meaning of Treas. Reg. Section 1.409A-3(i)(5).

“Change in Control Benefit” means, as of the date of a Qualifying Termination, a one-time lump sum payment equal to: (i)[●]1 ([●]) times the sum of (A) Individual’s then current base annual salary and (B) the Target Bonus for the year that includes the effective date of termination; plus (ii) an amount equal to the cost to Individual under COBRA to extend his or her then-current medical insurance benefits (i.e., the health, dental and/or vision benefits as elected by Individual under the Company’s health plan as of the time of such termination) for eighteen (18) months following the effective date of termination.

“COBRA” means the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended.

“Code” means the Internal Revenue Code of 1986, as amended, and any successor statute or statutes.

“Committee” means the Governance and Compensation Committee of the Board.

“Company” shall have the meaning set forth in the preamble hereto.

“Company Group” means the Company, ENLC, ENLK MLP, ENLK GP, ENLC Manager and each of their respective direct or indirect Subsidiaries.

“Confidential Information” shall have the meaning set forth in Section 3.1.

“Disability” means a physical or mental condition of Individual that, (i) in the good faith judgment of the Company, (A) prevents Individual from being able to perform the responsibilities of his or her position with the Company Group, (B) has continued for a period of at least one hundred eighty (180) days (whether consecutive or non-consecutive) during any twelve (12) month period, and (C) is expected to continue, or (ii) qualifies Individual to receive benefits under the Company’s long-term disability plan.

“Effective Date” shall have the meaning set forth in the preamble hereto.

“ENLC” means EnLink Midstream, LLC, a Delaware limited liability company.

“ENLC Manager” means EnLink Midstream Manager, LLC, a Delaware limited liability company.

“ENLK GP” means EnLink Midstream GP, LLC, a Delaware limited liability company.

“ENLK MLP” means EnLink Midstream Partners, LP, a Delaware limited partnership.

“Exchange Act” means the Securities and Exchange Act of 1934, as amended.

“GIP” means Global Infrastructure Partners III-A/B, L.P., Global Infrastructure Partners III-C Intermediate, L.P., Global Infrastructure Partners III-C2 Intermediate, L.P., Global Infrastructure Partners II-C Stetson AIV, L.P. and each of their affiliates, and any funds, partnerships or other investment vehicles managed by

1 Executive Chairman and CEO = 3 times; EVPs = 2.5 times; SVP = 1.5 times

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Global Infrastructure Management, LLC or their affiliates (including in each case, any portfolio companies of such entities).

“Good Reason”means any one or more of the following without Individual’s consent: (i) a material reduction in Individual’s base annual salary; (ii) a material adverse change in Individual’s authority, duties or responsibilities (other than temporarily while Individual is physically or mentally incapacitated or as required by applicable law); (iii) a material breach by the Company of any material provision of this Agreement (or by a member of the Company Group of any material provision or any other written agreement between Individual and the Company Group member regarding his or her services thereto); or (iv) the Company requires that Individual move his or her principal place of employment to a location that is thirty (30) or more miles from his or her current principal place of employment and the new location is farther from his or her primary residence. Individual may not terminate his or her employment for “Good Reason” unless (A) Individual gives the Company written notice of the event within thirty (30) days of the occurrence of the event, (B) the Company fails to remedy the event within thirty (30) days following its receipt of the notice, and (C) Individual terminates his or her employment with the Company within sixty (60) days following the Company’s receipt of written notice. A non-renewal of this Agreement shall not alone constitute Good Reason.

“Individual” shall have the meaning set forth in the preamble hereto.

“Other Arrangement” shall have the meaning set forth in Section 5.3.

“Person” means any individual, partnership, joint venture, limited liability company, corporation, trust, unincorporated organization or any other entity.

“Protection Period” means the period beginning one hundred twenty (120) days prior to, and ending twenty-four (24) months following, the date on which a Change in Control takes place.

“Qualifying Termination” means the termination of Individual’s employment during a Protection Period (i) by the Company for a reason other than Cause, Disability, or death, or (ii) by Individual for Good Reason. The transfer of Individual from the Company to another member of the Company Group shall not constitute a termination of employment.

“Renewal Date” shall have the meaning set forth in Section 5.1.

“Severance Agreement” shall have the meaning set forth in Section 2.3.

“Severance Plan” shall have the meaning set forth in Section 2.3.

“Subsidiary” means (i) in the case of a corporation, any corporation of which an applicable Person directly or indirectly owns shares representing more than fifty percent (50%) of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation and (ii) in the case of a partnership, limited liability company, or other business entity not organized as a corporation, any such business entity of which an applicable Person (A) directly or indirectly owns more than fifty percent (50%) of the voting, capital or profits interests (whether in the form of partnership interests, membership interests, or otherwise) or (B) has the power to elect or direct the election of directors with a majority of the voting power of the board of directors (or other governing body) of such partnership, limited liability company, or other business entity or the sole member or managing member of such partnership, limited liability company, or other business entity, as applicable.

“Target Bonus” means the amount of bonus that would be payable to Individual for the year in question if paid at one-hundred percent (100%) of Individual’s assigned bonus target percentage for such year as determined annually by the Committee or the Board, as applicable.

“Total Payment” shall have the meaning set forth in Section 2.4(a).

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“Voting Stock” of any specified Person as of any date means the capital stock (or comparable equity securities) of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors (or comparable governing body) of such Person.

ARTICLE II

Change in Control Payments

2.1    Change in Control Benefit; Release.

(a)    If Individual has a Qualifying Termination and Individual satisfies the conditions to the payment of a Change in Control Benefit as described below, the Company shall pay the Change in Control Benefit to Individual.

(b)    Any amounts payable under Section 2.1(a) shall be paid to Individual on the sixtieth (60th) day after the date Individual’s Qualifying Termination becomes effective for purposes of this Agreement; provided, however, that as a condition to receiving any such payment or payments, Individual (or Individual’s estate, as applicable) will be required to do both of the following: (i) execute and not revoke a general release of claims against the Company Group, with such general release becoming effective (and any applicable revocation period having lapsed) on or before the sixtieth (60th) day after the date Individual’s Qualifying Termination becomes effective for purposes of this Agreement, and (ii) execute a certification of compliance with his or her obligations to return Confidential Information.

2.2    Additional Benefits.

(a)    In the event of a Qualifying Termination, the Change in Control Benefit will be paid in addition to any accrued and unpaid compensation due to Individual as of his or her termination date, which may include (i) any unpaid bonus for any calendar year ending before Individual’s termination date that is actually earned by Individual (without regard to any requirement that Individual must remain employed by Company on the date such bonus is paid), and calculated in accordance with the terms of the applicable bonus arrangement that is in effect with respect to Individual during that year, (ii) accrued base salary and (iii) such other fringe benefits (other than any bonus, severance pay benefit, or medical insurance benefit) normally provided to similarly situated employees of the Company that shall have been earned up to the date of termination, including pay for accrued and unused paid-time-off (in accordance with the benefit policies then in effect).

(b)    Individual shall also be entitled to a prorated amount of the bonus (to the date of such Individual’s Qualifying Termination) for the calendar year in which Individual’s Qualifying Termination occurs to the extent such bonus would have otherwise been earned by Individual (had his or her employment not terminated due to a Qualifying Termination) in accordance with the terms of the applicable bonus arrangement that is in effect with respect to Individual during that year. Such prorated bonus shall not be made unless and until Individual has, as of such date, satisfied the conditions described in Section 2.1(b) above and shall be payable on the later of (i) the date that the bonus would have been paid under such applicable bonus arrangement (had Individual’s employment not terminated due to a Qualifying Termination), or (ii) the date on which Individual has satisfied the conditions described in Section 2.1(b) above.

(c)    For a period of twelve (12) months following Individual’s Qualifying Termination, or if Individual has not satisfied the conditions described in Section 2.1(b) above, for a period of sixty (60) days after the date of Individual’s termination, the Company shall, at its sole expense, provide Individual with outplacement services, the scope and provider of which shall be selected by Individual in his or her discretion; provided, however, that (i) any expense for such outplacement services shall be paid or reimbursed by the Company as soon as practicable after such expense is incurred, but in no event later than (A) thirty (30) days after such expense is incurred if incurred directly by the Company, or (B) thirty (30) days after such expense is submitted by Individual to Company for reimbursement, and (ii) the total amount of the expenses paid or reimbursed by the Company pursuant to this Section 2.2(c) shall not exceed $50,000.

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(d)    To the extent Individual is eligible to earn a Target Bonus, Individual’s assigned bonus target percentage shall not be materially reduced during any time (i) that Individual is employed during a Protection Period by a member of the Company Group or (ii) following Individual’s termination or separation for any reason that occurs within a Protection Period other than his or her involuntary termination for Cause or voluntary termination without Good Reason.

2.3    Non-duplication. The amount payable to Individual under Sections 2.1 and 2.2 is in lieu of, and not in addition to, any severance payment due or to become due to Individual under (i) any separate agreement or contract between Individual and the Company or any other member of the Company Group, (ii) any severance payment plan, program, policy or practice of the Company or any other member of the Company Group or (iii) any severance benefit required by law (collectively clauses (i)-(iii), a “Severance Plan”), it being understood that any equity-related award granted to Individual under the long-term incentive plans of a member of the Company Group shall not constitute a Severance Plan for purposes of this Section 2.3. In particular, no amounts shall be payable under the Severance Agreement between the Company and Individual in effect as of the date hereof (the “Severance Agreement”) if benefits are payable pursuant to this Agreement.

2.4    Potential Parachute Payment Adjustment.

(a)    If the payments and benefits provided to Individual under this Agreement or under any other agreement with, or plan of, the Company or any Person or entity which is a party to a transaction involving the Company or its affiliates (the “Total Payment”) (i) constitute a “parachute payment” as defined in Code Section 280G and exceed three (3) times Individual’s “base amount” as defined under Code Section 280G(b)(3), and (ii) would, but for this Section 2.4(a), be subject to the excise tax imposed by Code Section 4999, then Individual’s payments and benefits under this Agreement shall be either (A) paid in full, or (B) reduced and payable only as to the maximum amount which would result in no portion of such payments and benefits being subject to excise tax under Code Section 4999, whichever results in the receipt by Individual on an after-tax basis of the greatest amount of Total Payment (taking into account the applicable federal, state and local income taxes, the excise tax imposed by Code Section 4999 and all other taxes (including any interest and penalties) payable by Individual). If a reduction of the Total Payment is necessary, cash payments provided for herein shall first be reduced (such reduction to be applied first to the earliest payments otherwise scheduled to occur), and the non-cash benefits provided for herein shall thereafter be reduced (such reduction to be applied first to the benefits otherwise scheduled to occur the earliest). If, as a result of any reduction required by this Section 2.4(a), amounts previously paid to Individual exceed the amount to which Individual is entitled, Individual will promptly return the excess amount to the Company.

(b)    All determinations required to be made under this Section 2.4, including whether reductions are necessary, may be made, in the discretion of the Company, by an accounting or financial consulting firm selected by the Company for such purposes (the “Accounting Firm”). The Accounting Firm shall provide detailed supporting calculations both to the Company and to Individual. All fees and expenses of the Accounting Firm shall be borne solely by the Company.

2.5    Death or Disability of Individual. Except as otherwise provided in this Section 2.5, if Individual’s employment terminates due to death or Disability, then this Agreement shall terminate without further obligations to Individual or his or her estate, as applicable, under this Agreement. In either event, however, the Company, in addition to any obligations owed to Individual under any other applicable agreement with any member of the Company Group (i) will pay any accrued and unpaid compensation due to Individual as of his or her termination date, as described in Section 2.2(a) as if Individual’s termination of employment had been a Qualifying Termination, and (ii) will pay the prorated bonus described in Section 2.2(b) as if Individual’s termination of employment had been a Qualifying Termination; provided that payment of such compensation and benefits with respect to Section 2.2(b) shall only be made if Individual or his or her legal representative or his or her estate, as applicable, has satisfied the conditions described in Section 2.1(b).

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ARTICLE III

Confidential Information and Non-Competition; Other Covenants

3.1    Covenant Not to Disclose Confidential Information. Individual acknowledges that, during the course of his or her employment with the Company, he or she has or will have access to and knowledge of certain information and data that the Company or other members of the Company Group consider confidential and that the release of such information or data to unauthorized Persons would be extremely detrimental to the Company Group. As a consequence, Individual hereby agrees and acknowledges that he or she owes a duty to the Company not to disclose, and agrees that, during or after the term of his or her employment, without the prior written consent of the Company, he or she will not communicate, publish or disclose, to any Person anywhere or use any Confidential Information (as hereinafter defined) for any purpose other than carrying out his or her duties as contemplated in connection with his or her employment with respect to the Company or any Company Group member. Individual will use his or her best efforts at all times to hold in confidence and to safeguard any Confidential Information from falling into the hands of any unauthorized Person and, in particular, will not permit any Confidential Information to be read, duplicated, or copied. Notwithstanding the foregoing, Individual may disclose such Confidential Information to the extent required by applicable law or as a consequence of any judicial or regulatory proceeding, based upon the opinion of legal counsel and only after Individual has requested that such Confidential Information be preserved to the maximum extent practicable. To the extent permitted by law, Individual will advise the Company in advance of any intended disclosure to comply with legal requirements. Individual will return to the Company all Confidential Information in Individual’s possession or under Individual’s control when the duties of Individual no longer require Individual’s possession thereof, or whenever the Company shall so request, and in any event will promptly return all such Confidential Information if Individual’s relationship with the Company is terminated for any reason and will not retain any copies thereof. Notwithstanding the foregoing, nothing herein prohibits Individual from reporting possible violations of law or regulation to any governmental agency or entity, including but not limited to the Department of Justice, the Securities and Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of federal or state law or regulation. Individual does not need the prior authorization of the Company to make any such reports or disclosures, and Individual is not required to notify the Company that he or she has made such reports or disclosures. Individual shall not be held criminally or civilly liable under any federal or state trade secret law for the disclosure of a trade secret that (i) is made (A) in confidence to a federal, state, or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. For purposes hereof, the term “Confidential Information” shall mean any information or data used by or belonging or relating to the Company or any other member of the Company Group or any of their representatives that is not known generally to the industry in which any member of the Company Group is or may be engaged (other than as a result of disclosure by Individual in violation of this Agreement), including without limitation, any and all trade secrets, proprietary data and information relating to any member of the Company Group’s past, present, or future business and products, price lists, customer lists, processes, procedures or standards, know-how, manuals, business strategies, records, drawings, specifications, designs, financial information, whether or not reduced to writing, or information or data that the Company or any other member of the Company Group advises Individual should be treated as confidential information.

3.2    Covenant Not to Compete. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company, Individual shall not, unless Individual receives the prior written consent of the Board, own an interest in, manage, operate, join, control, lend money or render financial or other assistance to or participate in or be connected with, as an officer, manager, employee, partner, stockholder, consultant, or otherwise, any Person that competes with any member of the Company Group in (i) the purchasing, selling, brokering or marketing of natural gas, natural gas liquids, oil, hydrocarbons, brine, water or any derivative product thereof, including, without limitation, locating buyers and sellers, or negotiating purchase and sales contracts; (ii) the gathering, processing, fractionation, stabilization, and/or transporting of natural gas, natural gas liquids, oil, hydrocarbons, brine, water, or any derivative product thereof; or (iii) the conduct of a business enterprise that is in a business segment that contributes five percent (5%) or more to the Company’s gross revenue or deploys five percent (5%) or more of the Company’s fixed assets. Ownership by Individual, as a passive investment, of less than one half of one percent (0.5%) of the outstanding securities of any organization with securities listed on a national securities exchange or publicly traded in the over-the-counter market shall not constitute a breach of this Section 3.2.

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3.3    Covenant not to Solicit Customers. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company and for a period of twelve (12) months after the termination of such employment (for any reason), Individual shall not (i) persuade or encourage any Person that was a client or customer of any member of the Company Group at any time during the twelve (12) months prior to the termination of Individual’s employment to cease conducting or fail to renew existing business with that member of the Company Group, or (ii) use any confidential or proprietary information of any member of the Company Group to directly or indirectly solicit business from, or to interrupt, disturb, or interfere with any member of the Company Group’s relationships with, any Person that was a client or customer of any member of the Company Group at any time during the twelve (12) months prior to the termination of Individual’s employment.

3.4    Covenant not to Solicit Employees. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company and for a period of twenty-four (24) months after the termination of such employment (for any reason), Individual shall not solicit, endeavor to entice or induce any employee of any member of the Company Group to terminate such Person’s employment or service with such member or accept employment with anyone else; provided, however, that a general solicitation of the public for employment shall not constitute a solicitation hereunder.

3.5    Covenant Against Disparagement. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company and thereafter, he or she will not make any statements disparaging any member of the Company Group or any of their officers, directors, or employees that could reasonably be expected to be harmful to the interests of the Company or the Company Group. This covenant shall not apply to any statement made in the context of any legal or regulatory proceeding or the reporting of possible violations of law or regulation to a governmental agency or entity, as described in Section 3.1.

3.6    Specific Performance. Recognizing that irreparable damage will result to the Company in the event of the breach or threatened breach of any of the foregoing covenants and assurances by Individual contained in this Article III, and that the Company’s remedies at law for any such breach or threatened breach will be inadequate, the Company and its successors and assigns, in addition to such other remedies that may be available to them, shall be entitled to an injunction, including a mandatory injunction (without the necessity of (i) proving irreparable harm, (ii) establishing that monetary damages are inadequate, or (iii) posting any bond with respect thereto), to be issued by any court of competent jurisdiction ordering compliance with this Agreement or enjoining and restraining Individual, and each and every Person, firm, or company acting in concert or participation with him or her, from the continuation of such breach and, in addition thereto, he or she shall pay to the Company all ascertainable damages, including costs and reasonable attorneys’ fees sustained by the Company or any other member of the Company Group by reason of the breach or threatened breach of said covenants and assurances.

3.7    Clawback. Individual agrees that in the event that the Company determines that Individual has breached any term of this Article III, in addition to any other remedies at law or in equity the Company may have available to it, the Company may in its sole discretion require that Individual repay to the Company, within five (5) business days of receipt of written demand therefor, an amount equal to the amounts paid to or on behalf of Individual pursuant to Sections 2.1, 2.2(b) and 2.2(c).

3.8    Miscellaneous.

(a)    Individual has carefully read and considered the provisions of this Article III and, having done so, agrees that the restrictions set forth in this Article III (including the relevant time periods, scope of activity to be restrained, and the geographical scope) are fair and reasonable and are reasonably required for the protection of the interests of the Company Group and their respective officers, directors, managers, employees, creditors, partners, members, and unitholders. Individual understands that the restrictions contained in Article III may limit his or her ability to engage in a business similar to the business of any member of the Company Group but acknowledges that he or she will receive sufficiently high remuneration and other benefits from the Company Group to justify such restrictions.

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(b)    The covenants and obligations of Individual set forth in this Article III are in addition to, and not in lieu of, or exclusive of, any other obligations and duties of Individual to the Company Group, whether express or implied in fact or in law.

(c)    In the event that any provision of this Article III relating to the relevant time periods, scope of activity and/or the areas of restriction hereunder shall be declared by a court of competent jurisdiction to exceed the maximum time period, scope or areas such court deems reasonable and enforceable, the relevant time periods, scope of activity, and/or areas of restriction deemed reasonable and enforceable by the court shall become and thereafter be the maximum time period, scope of activity, and/or areas.

ARTICLE IV

Dodd-Frank Clawback

Individual agrees and acknowledges that any and all compensation Individual receives pursuant to this Agreement shall be subject to clawback by the Company to the extent provided in policies adopted by the Board to comply with the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

ARTICLE V

Miscellaneous

5.1    Term; Termination or Amendment.

(a)    Unless, this Agreement is terminated in accordance with Section 5.1(b) below, this Agreement shall extend for a term (the “Term”) commencing on the Effective Date and ending on December 31, 20__ (the “Initial Expiration Date”). If this Agreement is not previously terminated, the Term shall automatically review for one (1) additional year beginning on the day following the Initial Expiration Date and each subsequent anniversary thereof (each, a “Renewal Date”), unless the Company elects not to extend the Term by providing Individual with written notice (a “Non-Renewal Notice”) of such election not less than ninety (90) days prior to the last day of the then-current Term (each of the Initial Expiration Date and the last day of any then-current extended Term, the “Expiration Date”). Except as otherwise provided in the preceding sentence, no such termination or any amendment of this Agreement shall become effective during the term of this Agreement without Individual’s written consent, and any such purported termination or amendment of this Agreement during a Protection Period, whether pursuant to the preceding sentence or otherwise, without Individual’s written consent shall become effective no earlier than the expiration of the Protection Period.

(b) If this Agreement is not previously terminated, this Agreement shall terminate upon the termination of Individual’s employment; provided that, all obligations and liabilities of the parties hereto arising in connection with such termination of employment or otherwise accruing under this Agreement shall survive such termination.

(c)    The Company shall have the right to amend this Agreement without Individual’s consent, which amendment shall be evidenced in writing and be effective as of the relevant Renewal Date; provided that, (i) Individual is provided with written notice of the Company’s election to amend the Agreement at least ninety (90) days prior to such Renewal Date, and (ii) no such amendment adversely affects Individual.

5.2    Interpretation. The Article and Section headings herein are for convenience only and shall not affect the construction hereof. In this Agreement, unless a clear contrary intention appears, (i) the words “herein,” “hereof,” and “hereunder” and other words of similar import refer to this Agreement as a whole and not to any particular Article, Section or other subdivision, (ii) reference to any Article or Section, means such Article or Section hereof, (iii) the word “including” (and with correlative meaning “include”) means including, without limiting the generality of any description preceding such term, and (iv) where any provision of this Agreement refers to action to be taken by either party, or which such party is prohibited from taking, such provision shall be applicable whether such action is taken directly or indirectly by such party.

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5.3    Effect on Other Plans. Except in the case of a Severance Plan, as defined in Section 2.3, nothing in this Agreement shall prevent or limit Individual’s continuing or future participation in any other plan, program, policy or practice provided by the Company or any other member of the Company Group for which Individual may qualify, nor shall anything herein limit or otherwise affect such rights as Individual may have under any other contract or agreement with the Company or any other member of the Company Group. Amounts which are vested benefits or which Individual is otherwise entitled to receive under any such other plan, policy, practice, program, contract or agreement (“Other Arrangement”) at or subsequent to the termination of Individual’s employment shall be payable in accordance with such Other Arrangement except as explicitly modified by this Agreement; provided, however, the time period after such termination shall not be credited as continued employment of Individual for any purpose under any such Other Arrangement.

5.4    Overpayments. Individual agrees that the Company, in its sole discretion, may require repayment by Individual of any amount erroneously made in excess of the amounts that should have been paid under the terms of this Agreement.

5.5    Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

5.6    No Breach. Individual represents and warrants to the Company that neither the execution nor delivery of this Agreement, nor the performance of Individual’s obligations hereunder will conflict with, or result in a breach of, any term, condition, or provision of, or constitute a default under, any obligation, contract, agreement, covenant, or instrument to which Individual is a party or under which Individual is bound, including without limitation, the breach by Individual of a fiduciary or contractual duty to any former employers.

5.7    Entire Agreement; Manner of Amendment. Except with respect to the Severance Agreement, and subject to Section 2.3, this Agreement cancels and supersedes all previous agreements relating to the subject matter of this Agreement, written or oral, between the parties hereto and their respective affiliates and contains the entire understanding of the parties hereto. This Agreement shall not be amended, modified or supplemented in any manner whatsoever except by mutual written agreement of the parties hereto or in accordance with Section 5.1. Failure of the Company to demand strict compliance with any of the terms, covenants or conditions hereof shall not be deemed a waiver of the term, covenant or condition, nor shall any waiver or relinquishment by the Company of any right or power hereunder at any one time or more times be deemed a waiver or relinquishment of the right or power at any other time or times.

5.8    Governing Law; Venue. This Agreement and all rights and obligations of the parties hereunder shall be governed by, and construed and interpreted in accordance with, the laws of the State of Texas, including all matters of enforcement, validity, and performance without regard to conflict or choice of law principles. Except for injunction actions or proceedings initiated by the Company pursuant to Section 3.6, venue for any action or proceeding relating to this Agreement and/or Individual’s employment relationship with the Company and the Company Group, as applicable, shall lie exclusively in courts in Dallas County, Texas.

5.9    Notices. All notices and all other communications provided for in the Agreement shall be in writing and addressed (i) if to the Company, at its principal office address or such other address as it may have designated by written notice to Individual for purposes hereof, directed to the attention of the Board with a copy to the Secretary of the Company and (ii) if to Individual, at his or her residence address on the records of the Company or to such other address as he or she may have designated to the Company in writing for purposes hereof. Each such notice or other communication shall be deemed to have been duly given when personally delivered or sent by United States registered mail, return receipt requested, postage prepaid, or by a nationally recognized overnight delivery service, with delivery confirmed.

5.10    Assignment. This Agreement is personal and not assignable by Individual but it may be assigned by the Company without notice to or consent of Individual to, and shall thereafter be binding upon and enforceable by, (i) any member of the Company Group, or (ii) any Person that acquires or succeeds to substantially all of the business or assets of any member of the Company Group (and such Person shall be deemed included in the definition of the “Company” and the “Company Group” for all purposes of this Agreement).

9

5.11    Tax Withholdings. The Company shall withhold from all payments hereunder all applicable taxes (federal, state or other) that it is required to withhold therefrom.

5.12    Employment with Affiliates. For purposes of this Agreement, employment with any member of the Company Group shall be deemed to be employment with the Company.

5.13    Company Actions. Actions taken hereunder by the Company, including any determinations or exercises of discretion pursuant to this Agreement, shall be undertaken (i) with the approval of the Board, with respect to (A) the adoption of any amendment hereto under Sections 5.1 or 5.7 of this Agreement, (B) an election not to extend the Term under Section 5.1 of this Agreement, and (C) in the event Individual is an “executive officer” under the Securities Exchange Act of 1934, as amended, (1) the determination to terminate Individual’s employment for Cause when applicable and for purposes of this Agreement, (2) the determination of whether any other termination of Individual’s employment constitutes a Qualifying Termination or arises due to his or her Disability, and (3) the exercise of the clawback, repayment and similar remedies of the Company under Article IV and Sections 3.7 and 5.4 of this Agreement; (ii) in the event Individual is an “executive officer” under the Securities Exchange Act of 1934, as amended, with the approval of the Board or the Committee with respect to (A) the placement of Individual on paid leave while a determination is being made as to whether there is a basis to terminate Individual’s employment for Cause, and (B) the determination of which actions, if any, are appropriate to remedy an event pursuant to clause (B) of the definition of Good Reason herein; and (iii) with the approval of the Board or the Committee or by [the Chief Executive Officer of EnLink Midstream, LLC] with respect to (A) the selection of the Accounting Firm pursuant to Section 2.4(b) of this Agreement; (B) the seeking of an injunction pursuant to Section 3.6 of this Agreement, and (C) in the event Individual is not an “executive officer” under the Securities Exchange Act of 1934, as amended, (1) the determination to terminate Individual’s employment for Cause when applicable and for purposes of this Agreement, (2) the determination of whether any other termination of Individual’s employment constitutes a Qualifying Termination or arises due to his or her Disability, (3) the placement of Individual on paid leave while a determination is being made as to whether there is a basis to terminate Individual’s employment for Cause, (4) the determination of which actions, if any, are appropriate to remedy an event pursuant to clause (B) of the definition of Good Reason herein, (5) the exercise of the clawback, repayment and similar remedies of the Company under Article IV and Sections 3.7 and 5.4 of this Agreement, and (6) the exercise of any other authority or discretion that is not described above, but is otherwise necessary or appropriate in order to satisfy the obligations and duties of, or to exercise the rights of, the Company for purposes of this Agreement. Notwithstanding any provision herein to the contrary, to the extent such actions relate only to Individual, and Individual is then serving as [the Chief Executive officer of EnLink Midstream, LLC] or as a member of the Board or Committee, such actions shall be undertaken by the Board or Committee without the participation of Individual in the authorization thereof.

5.14    Expenses. If any action at law or in equity is necessary to enforce or interpret the terms of this Agreement, the prevailing party shall be entitled to reasonable attorneys’ fees, in addition to any other relief to which such party may be entitled.

5.15    Section 409A. This Agreement is intended to provide payments that are (i) exempt from the provisions of Code Section 409A and related regulations and Treasury pronouncements, by complying with (among other things) the short-term deferral exception as specified in Treasury Regulation § 1.409A-1(b)(4) and the involuntary separation pay exception within the meaning of Treasury Regulation § 1.409A-1(b)(9)(iii), or (ii) compliant with the provisions of Code Section 409A and related regulations and Treasury pronouncements, and this Agreement shall be administered, interpreted and construed accordingly. Any other provision of this Agreement to the contrary notwithstanding, the parties agree that any benefit or benefits under this Agreement that the Company determines are subject to the suspension period under Code Section 409A(a)(2)(B) shall not be paid or commence until such date that constitutes the first business day following six (6) months after Individual’s termination date, or if earlier, Individual’s death.

5.16    Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same instrument.

10

[Remainder of Page Intentionally Left Blank]

11

IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed, and Individual has hereunto set his or her hand, as of the Effective Date.

ENLINK MIDSTREAM OPERATING, LP

By: ENLINK MIDSTREAM OPERATING GP, LLC,

Its general partner

_____________________________

Name:Barry E. Davis

Title:Chairman and Chief Executive Officer

INDIVIDUAL:

Name: _________________________________

12

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Barry E. Davis, certify that:

1.I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.    The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 5, 2020	/s/ BARRY E. DAVIS
	Barry E. Davis
	Chairman and Chief Executive Officer
	(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Pablo G. Mercado, certify that:

1.I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.    The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 5, 2020	/s/ PABLO G. MERCADO
	Pablo G. Mercado
	Executive Vice President and Chief Financial Officer
	(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of EnLink Midstream, LLC (the “Registrant”) on Form 10-Q of EnLink Midstream, LLC for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned, Barry E. Davis, Chief Executive Officer of EnLink Midstream Manager, LLC, and Pablo G. Mercado, Chief Financial Officer of EnLink Midstream Manager, LLC, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 5, 2020	/s/ BARRY E. DAVIS
	Barry E. Davis
	Chief Executive Officer
Date: November 5, 2020	/s/ PABLO G. MERCADO
	Pablo G. Mercado
	Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Registrant and will be retained by the Registrant and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report.

XML

Cover Page - shares	9 Months Ended
	Sep. 30, 2020	Oct. 29, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2020
Document Transition Report	false
Entity File Number	001-36336
Entity Registrant Name	ENLINK MIDSTREAM, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-4108528
Entity Address, Address Line One	1722 Routh St., Suite 1300
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75201
City Area Code	214
Local Phone Number	953-9500
Title of 12(b) Security	Common Units Representing Limited Liability Company Interests
Trading Symbol	ENLC
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		489,746,802
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2020
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 78.9	$ 77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.5, respectively	58.3	36.2
Accrued revenue and other	352.9	460.1
Fair value of derivative assets	9.6	12.9
Other current assets	81.7	57.8
Total current assets	581.4	644.4
Property and equipment, net of accumulated depreciation of $3,775.9 and $3,418.6, respectively	6,742.0	7,081.3
Intangible assets, net of accumulated amortization of $638.0 and $545.9, respectively	1,156.2	1,249.9
Goodwill	0.0	184.6
Investment in unconsolidated affiliates	41.9	43.1
Fair value of derivative assets	5.4	4.3
Other assets, net	140.3	128.2
Total assets	8,667.2	9,335.8
Current liabilities:
Accounts payable and drafts payable	54.4	70.6
Accounts payable to related party	0.9	1.1
Accrued gas, NGLs, condensate, and crude oil purchases	214.8	354.8
Fair value of derivative liabilities	33.1	14.4
Other current liabilities	198.8	206.2
Total current liabilities	502.0	647.1
Long-term debt	4,650.0	4,764.3
Asset retirement obligations	16.1	15.5
Other long-term liabilities	83.5	90.8
Fair value of derivative liabilities	4.5	6.8
Redeemable non-controlling interest	0.0	5.2
Members’ equity:
Members’ equity (489,734,530 and 487,791,612 units issued and outstanding, respectively)	1,701.2	2,135.5
Accumulated other comprehensive loss	(19.0)	(11.0)
Non-controlling interest	1,728.9	1,681.6
Total members’ equity	3,411.1	3,806.1
Total liabilities and members’ equity	$ 8,667.2	$ 9,335.8

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
ASSETS
Allowance for bad debt	$ 0.5	$ 0.5
Property and equipment, accumulated depreciation	3,775.9	3,418.6
Intangible assets, accumulated amortization	$ 638.0	$ 545.9
Members’ equity:
Common units issued (in shares)	489,734,530	487,791,612
Common units outstanding (in shares)	487,791,612	489,734,530

XML

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Revenues:
Revenue from contracts with customers	$ 933.6	$ 1,400.5	$ 2,837.8	$ 4,881.0
Gain (loss) on derivative activity	(5.1)	7.5	(8.3)	16.2
Total revenues	928.5	1,408.0	2,829.5	4,897.2
Operating costs and expenses:
Cost of sales	549.5	999.5	1,702.5	3,663.0
Operating expenses	94.3	119.2	283.1	351.6
General and administrative	25.7	38.5	79.6	122.1
(Gain) loss on disposition of assets	(1.8)	(3.0)	2.8	(2.9)
Depreciation and amortization	160.3	157.3	481.3	463.1
Impairments	0.0	0.0	354.5	186.5
Loss on secured term loan receivable	0.0	0.0	0.0	52.9
Total operating costs and expenses	828.0	1,311.5	2,903.8	4,836.3
Operating income (loss)	100.5	96.5	(74.3)	60.9
Other income (expense):
Interest expense, net of interest income	(55.5)	(56.6)	(166.3)	(160.5)
Gain on extinguishment of debt	0.0	0.0	32.0	0.0
Income (loss) from unconsolidated affiliates	(0.2)	4.0	0.8	14.0
Other income (expense)	0.4	(0.1)	0.4	0.1
Total other expense	(55.3)	(52.7)	(133.1)	(146.4)
Income (loss) before non-controlling interest and income taxes	45.2	43.8	(207.4)	(85.5)
Income tax benefit (expense)	(6.0)	(6.3)	16.0	(2.7)
Net income (loss)	39.2	37.5	(191.4)	(88.2)
Net income attributable to non-controlling interest	26.6	25.7	78.7	92.4
Net income (loss) attributable to ENLC	$ 12.6	$ 11.8	$ (270.1)	$ (180.6)
Net income (loss) attributable to ENLC per unit:
Basic common unit (in dollars per share)	$ 0.03	$ 0.02	$ (0.55)	$ (0.40)
Diluted common unit (in dollars per share)	$ 0.03	$ 0.02	$ (0.55)	$ (0.40)
Product sales
Revenues:
Revenue from contracts with customers	$ 696.1	$ 1,137.2	$ 2,121.6	$ 4,118.5
Midstream services
Revenues:
Revenue from contracts with customers	$ 237.5	$ 263.3	$ 716.2	$ 762.5

XML

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2020		Sep. 30, 2019		Sep. 30, 2020	Sep. 30, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 39.2		$ 37.5		$ (191.4)	$ (88.2)
Gain (loss) on designated cash flow hedge	[1]	3.6	[2]	(1.3)	[3]	(8.0)	(11.2)
Comprehensive income (loss)		42.8		36.2		(199.4)	(99.4)
Comprehensive income attributable to non-controlling interest		26.6		25.7		78.7	92.4
Comprehensive income (loss) attributable to ENLC		$ 16.2		$ 10.5		$ (278.1)	$ (191.8)

[1] Includes a tax expense of $1.1 million and a tax benefit of $2.4 million for the three and nine months ended September 30, 2020, respectively, and a tax benefit of $0.5 million and $4.1 million for the three and nine months ended September 30, 2019, respectively.

[2] Includes a tax expense of $1.1 million.

[3] Includes a tax benefit of $0.5 million.

XML

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020		Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ 1.1	[1]	$ 0.5	$ (4.0)	$ (0.5)	$ (3.6)	$ (2.4)	$ (4.1)

[1] Includes a tax expense of $1.1 million and a tax benefit of $2.4 million for the three and nine months ended September 30, 2020, respectively, and a tax benefit of $0.5 million and $4.1 million for the three and nine months ended September 30, 2019, respectively.

XML

Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Cumulative Effect, Period of Adoption, Adjustment	Cumulative Effect, Period of Adoption, Adjusted Balance	Common Units	Common Units Cumulative Effect, Period of Adoption, Adjustment	Common Units Cumulative Effect, Period of Adoption, Adjusted Balance	Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss Cumulative Effect, Period of Adoption, Adjusted Balance	Non-Controlling Interest	Non-Controlling Interest Cumulative Effect, Period of Adoption, Adjusted Balance	Redeemable Non-Controlling Interest (Temporary Equity)	Redeemable Non-Controlling Interest (Temporary Equity) Cumulative Effect, Period of Adoption, Adjusted Balance
Member equity, beginning balance at Dec. 31, 2018		$ 4,974.2		$ 0.3	$ 4,974.5	$ 1,730.9	$ 0.3	$ 1,731.2	$ (2.0)	$ (2.0)	$ 3,245.3	$ 3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018						181,300,000		181,300,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(8.4)				$ (5.6)					(2.8)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						1,000,000.0
Unit-based compensation		13.6				$ 12.2					1.4
Contributions from non-controlling interests		15.7									15.7
Distributions		(178.6)				(51.0)					(127.6)
Fair value adjustment related to redeemable non-controlling interest		2.5				2.5							$ (2.1)
Net income (loss)		(134.8)				(176.3)					41.5		0.0
Issuance of common units for ENLK public common units related to the Merger		399.0				$ 1,958.1					(1,559.1)
Issuance of common units for ENLK public common units related to the Merger (in shares)						304,900,000
Member equity, end balance at Mar. 31, 2019		5,083.5				$ 3,471.1			(2.0)		1,614.4
Units outstanding, end balance (in shares) at Mar. 31, 2019						487,200,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2018													9.3	$ 9.3
Increase (Decrease) in Temporary Equity
Distributions		(178.6)				$ (51.0)					(127.6)
Fair value adjustment related to redeemable non-controlling interest		2.5				2.5							(2.1)
Redeemable noncontrolling interest, ending balance at Mar. 31, 2019													7.2
Member equity, beginning balance at Dec. 31, 2018		4,974.2		$ 0.3	$ 4,974.5	$ 1,730.9	$ 0.3	$ 1,731.2	(2.0)	$ (2.0)	3,245.3	$ 3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018						181,300,000		181,300,000
Increase (Decrease) in Members' Equity
(Loss) gain on designated cash flow hedge	[1]	(11.2)
Member equity, end balance at Sep. 30, 2019		4,863.4				$ 3,205.7			(13.2)		1,670.9
Units outstanding, end balance (in shares) at Sep. 30, 2019						487,600,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2018													9.3	$ 9.3
Increase (Decrease) in Temporary Equity
Redemption of non-controlling interest		0.0
Redeemable noncontrolling interest, ending balance at Sep. 30, 2019													5.5
Member equity, beginning balance at Mar. 31, 2019		5,083.5				$ 3,471.1			(2.0)		1,614.4
Units outstanding, beginning balance (in shares) at Mar. 31, 2019						487,200,000
Increase (Decrease) in Members' Equity
Unit-based compensation		6.6				$ 6.6					0.0
Contributions from non-controlling interests		29.5									29.5
Distributions		(172.3)				(137.2)					(35.1)
(Loss) gain on designated cash flow hedge	[2]	(9.9)							(9.9)
Fair value adjustment related to redeemable non-controlling interest		0.2				0.2					0.0		(1.4)
Net income (loss)		9.1				(16.1)					25.2		0.0
Member equity, end balance at Jun. 30, 2019		4,946.7				$ 3,324.6			(11.9)		1,634.0
Units outstanding, end balance (in shares) at Jun. 30, 2019						487,200,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2019													7.2
Increase (Decrease) in Temporary Equity
Distributions		(172.3)				$ (137.2)					(35.1)
Fair value adjustment related to redeemable non-controlling interest		0.2				0.2					0.0		(1.4)
Redeemable noncontrolling interest, ending balance at Jun. 30, 2019													5.8
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(2.1)				$ (2.1)					0.0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						400,000
Unit-based compensation		11.1				$ 11.1					0.0
Contributions from non-controlling interests		33.4									33.4
Distributions		(161.9)				(139.8)					(22.1)		(0.3)
(Loss) gain on designated cash flow hedge	[3]	(1.3)	[1]						(1.3)
Fair value adjustment related to redeemable non-controlling interest		0.1				0.1					0.0		(0.1)
Net income (loss)		37.4				11.8					25.6		0.1
Member equity, end balance at Sep. 30, 2019		4,863.4				$ 3,205.7			(13.2)		1,670.9
Units outstanding, end balance (in shares) at Sep. 30, 2019						487,600,000
Increase (Decrease) in Temporary Equity
Distributions		(161.9)				$ (139.8)					(22.1)		(0.3)
Fair value adjustment related to redeemable non-controlling interest		0.1				0.1					0.0		(0.1)
Redeemable noncontrolling interest, ending balance at Sep. 30, 2019													5.5
Member equity, beginning balance at Dec. 31, 2019		$ 3,806.1				$ 2,135.5			(11.0)		1,681.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2019		487,791,612				487,800,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		$ (4.0)				$ (4.0)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						1,300,000
Unit-based compensation		12.3				$ 12.3
Contributions from non-controlling interests		37.1									37.1
Distributions		(117.7)				(93.3)					(24.4)		(0.3)
(Loss) gain on designated cash flow hedge	[4]	(13.1)							(13.1)
Fair value adjustment related to redeemable non-controlling interest		0.7				0.7							(0.9)
Net income (loss)		(260.4)				(286.8)					26.4
Member equity, end balance at Mar. 31, 2020		3,461.0				$ 1,764.4			(24.1)		1,720.7
Units outstanding, end balance (in shares) at Mar. 31, 2020						489,100,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2019													5.2
Increase (Decrease) in Temporary Equity
Distributions		(117.7)				$ (93.3)					(24.4)		(0.3)
Redemption of non-controlling interest													(4.0)
Fair value adjustment related to redeemable non-controlling interest		0.7				0.7							(0.9)
Redeemable noncontrolling interest, ending balance at Mar. 31, 2020													0.0
Member equity, beginning balance at Dec. 31, 2019		$ 3,806.1				$ 2,135.5			(11.0)		1,681.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2019		487,791,612				487,800,000
Increase (Decrease) in Members' Equity
(Loss) gain on designated cash flow hedge	[1]	$ (8.0)
Member equity, end balance at Sep. 30, 2020		$ 3,411.1				$ 1,701.2			(19.0)		1,728.9
Units outstanding, end balance (in shares) at Sep. 30, 2020		489,734,530				489,700,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2019													5.2
Increase (Decrease) in Temporary Equity
Redemption of non-controlling interest		$ 4.0
Redeemable noncontrolling interest, ending balance at Sep. 30, 2020													0.0
Member equity, beginning balance at Mar. 31, 2020		3,461.0				$ 1,764.4			(24.1)		1,720.7
Units outstanding, beginning balance (in shares) at Mar. 31, 2020						489,100,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.3)				$ (0.3)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						400,000
Unit-based compensation		6.8				$ 6.8
Contributions from non-controlling interests		13.2									13.2
Distributions		(82.4)				(46.5)					(35.9)		0.0
(Loss) gain on designated cash flow hedge	[5]	1.5							1.5
Net income (loss)		29.8				4.1					25.7
Member equity, end balance at Jun. 30, 2020		3,429.6				$ 1,728.5			(22.6)		1,723.7
Units outstanding, end balance (in shares) at Jun. 30, 2020						489,500,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2020													0.0
Increase (Decrease) in Temporary Equity
Distributions		(82.4)				$ (46.5)					(35.9)		0.0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2020													0.0
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.4)				$ (0.4)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						200,000
Unit-based compensation		7.2				$ 7.2
Contributions from non-controlling interests		1.9									1.9
Distributions		(69.7)				(46.4)					(23.3)		(0.3)
(Loss) gain on designated cash flow hedge	[6]	3.6	[1]						3.6
Fair value adjustment related to redeemable non-controlling interest		(0.3)				(0.3)							0.3
Net income (loss)		39.2				12.6					26.6
Member equity, end balance at Sep. 30, 2020		$ 3,411.1				$ 1,701.2			$ (19.0)		1,728.9
Units outstanding, end balance (in shares) at Sep. 30, 2020		489,734,530				489,700,000
Increase (Decrease) in Temporary Equity
Distributions		$ (69.7)				$ (46.4)					$ (23.3)		(0.3)
Fair value adjustment related to redeemable non-controlling interest		$ (0.3)				$ (0.3)							0.3
Redeemable noncontrolling interest, ending balance at Sep. 30, 2020													$ 0.0

[1] Includes a tax expense of $1.1 million and a tax benefit of $2.4 million for the three and nine months ended September 30, 2020, respectively, and a tax benefit of $0.5 million and $4.1 million for the three and nine months ended September 30, 2019, respectively.

[2] Includes a tax benefit of $3.6 million.

[3] Includes a tax benefit of $0.5 million.

[4] Includes a tax benefit of $4.0 million.

[5] Includes a tax expense of $0.5 million.

[6] Includes a tax expense of $1.1 million.

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Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020		Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Stockholders' Equity [Abstract]
Income tax (benefit) expense	$ 1.1	[1]	$ 0.5	$ (4.0)	$ (0.5)	$ (3.6)	$ (2.4)	$ (4.1)

[1] Includes a tax expense of $1.1 million and a tax benefit of $2.4 million for the three and nine months ended September 30, 2020, respectively, and a tax benefit of $0.5 million and $4.1 million for the three and nine months ended September 30, 2019, respectively.

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Cash flows from operating activities:
Net loss	$ 39.2	$ 37.5	$ (191.4)	$ (88.2)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairments	0.0	0.0	354.5	186.5
Depreciation and amortization	160.3	157.3	481.3	463.1
Loss on secured term loan receivable	0.0	0.0	0.0	52.9
Deferred income tax (benefit) expense	5.6	5.6	(17.1)	0.7
Non-cash unit-based compensation			24.6	31.2
(Gain) loss on derivatives recognized in net loss	5.1	(7.5)	8.3	(16.2)
Cash settlements on derivatives			(1.0)	12.5
Gain on extinguishment of debt	0.0	0.0	(32.0)	0.0
Amortization of debt issue costs, net discount (premium) of notes			3.1	3.9
Distribution of earnings from unconsolidated affiliates			1.6	14.7
Income from unconsolidated affiliates	0.2	(4.0)	(0.8)	(14.0)
Other operating activities			2.1	(5.0)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other			85.3	338.6
Natural gas and NGLs inventory, prepaid expenses, and other			(12.7)	2.7
Accounts payable, accrued product purchases, and other accrued liabilities			(144.8)	(205.9)
Net cash provided by operating activities			561.0	777.5
Cash flows from investing activities:
Additions to property and equipment			(254.4)	(594.5)
Proceeds from sale of property			7.2	13.7
Other investing activities			(3.5)	(2.2)
Net cash used in investing activities			(250.7)	(583.0)
Cash flows from financing activities:
Proceeds from borrowings			690.0	2,855.0
Payments on borrowings			(776.0)	(2,591.4)
Debt financing costs			0.0	(10.0)
Conversion of restricted units, net of units withheld for taxes			(4.7)	(10.5)
Distribution to members			(186.2)	(328.0)
Distributions to non-controlling interests			(84.2)	(185.1)
Contributions by non-controlling interests			52.2	78.6
Other financing activities			0.1	(1.3)
Net cash used in financing activities			(308.8)	(192.7)
Net increase in cash and cash equivalents			1.5	1.8
Cash and cash equivalents, beginning of period			77.4	100.4
Cash and cash equivalents, end of period	$ 78.9	$ 102.2	78.9	102.2
Supplemental disclosures of cash flow information:
Cash paid for interest			125.7	128.0
Cash paid (refunded) for income taxes			(0.1)	2.8
Non-cash investing activities:
Non-cash accrual of property and equipment			(27.2)	24.6
Right-of-use assets obtained in exchange for operating lease liabilities			9.1	98.4
Non-cash financing activities:
Redemption of non-controlling interest			$ (4.0)	$ 0.0

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General

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

(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

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 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 energy, volatility in the market prices for these commodities, and a significant and persistent reduction in the market price of crude oil. As a result of the demand destruction, reduced commodity prices, and an uncertain timeline for full recovery, many oil and natural gas producers, including some of our customers, have curtailed their current drilling and production activity and reduced or slowed down their plans for future drilling and production activity. As a result of these decreases in producer activity, we experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems during portions of the first and second quarters, although volumes have since been restored nearly to pre-pandemic levels.

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 whether 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 that exist as of the date of this report will be extended or new measures will be reinstated. As a result, there is significant uncertainty regarding whether market dislocations will continue or increase and how significantly and how long they may 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).

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Significant Accounting Policies

(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.

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 nine months ended September 30, 2020, we had contractual commitments of $44.8 million and $128.0 million under our MVC contracts, respectively, and recorded $14.0 million and $39.2 million of revenue due to volume shortfalls, respectively.

MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)	$	65.3
2021	119.7
2022	102.1
2023	91.5
2024	77.4
Thereafter	144.9
Total	$	600.9

____________________________

(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 nine months ended September 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. For the three months ended September 30, 2020, we did not recognize any impairment related to property and equipment.

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, the 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 included in “Other current liabilities” on the consolidated balance sheet as of September 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 nine months ended September 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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Goodwill and Intangible Assets

9 Months Ended

Sep. 30, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

(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 nine months ended September 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 nine months ended September 30, 2020.

Goodwill Impairment Analysis for the nine months ended September 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
Nine Months Ended September 30, 2020
Customer relationships, beginning of period	$	1,795.8	$	(545.9)	$	1,249.9
Amortization expense	—		(92.7)		(92.7)
Retirements (1)	(1.6)		0.6		(1.0)
Customer relationships, end of period	$	1,794.2	$	(638.0)	$	1,156.2

____________________________

(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 for each of the three months ended September 30, 2020 and 2019, and $92.7 million and $92.8 million for the nine months ended September 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)	$	30.8
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8
Total	$	1,156.2

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Related Party Transactions

9 Months Ended

Sep. 30, 2020

Related Party Transactions [Abstract]

Related Party Transactions

(4) Related Party Transactions

Transactions with Cedar Cove JV. For the three and nine months ended September 30, 2020, we recorded cost of sales of $2.0 million and $6.2 million, respectively, and for the three and nine months ended September 30, 2019, we recorded cost of sales of $4.1 million and $18.0 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 $0.9 million and $1.1 million at September 30, 2020 and December 31, 2019, respectively.

Transactions with GIP. For the three and nine months ended September 30, 2020, we recorded general and administrative expenses of $0.2 million related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three and nine months ended September 30, 2019.

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.

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Long-Term Debt

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Long-Term Debt

(5) Long-Term Debt

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

	September 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)	$	300.0	$	—	$	300.0	$	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		1.1		522.9		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		(5.7)		444.3		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	$	4,682.3	$	(5.9)	4,676.4		$	4,800.0	$	(5.9)	4,794.1
Debt issuance cost (3)					(26.4)						(29.8)
Long-term debt, net of unamortized issuance cost					$	4,650.0					$	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 September 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 September 30, 2020 and December 31, 2019, respectively.

(3)Net of amortization of $13.7 million and $10.9 million at September 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 ($300.0 million as of September 30, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($19.3 million as of September 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. 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 September 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 September 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 September 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.

Senior Unsecured Notes Repurchases

For the nine months ended September 30, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. We and ENLK did not make any payments to repurchase senior notes during the three months ended September 30, 2020. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions):

	Nine Months Ended September 30, 2020
Debt repurchased	$	67.7
Aggregate payments	(36.0)
Net discount on repurchased debt	(0.3)
Accrued interest on repurchased debt	0.6
Gain on extinguishment of debt	$	32.0

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Income Taxes

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Income Taxes

(6) Income Taxes

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Current income tax expense	$	(0.4)	$	(0.7)	$	(1.1)	$	(2.0)
Deferred income tax benefit (expense)	(5.6)		(5.6)		17.1		(0.7)
Income tax benefit (expense)	$	(6.0)	$	(6.3)	$	16.0	$	(2.7)

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Expected income tax benefit (expense) based on federal statutory rate	$	(3.6)	$	(3.8)	$	60.0	$	37.4
State income tax benefit (expense), net of federal benefit	(0.6)		(0.7)		6.4		3.6
Unit-based compensation (1)	(1.6)		(1.3)		(6.0)		(1.3)
Non-deductible expense related to goodwill impairment	—		—		(43.4)		(43.8)
Other	(0.2)		(0.5)		(1.0)		1.4
Income tax benefit (expense)	$	(6.0)	$	(6.3)	$	16.0	$	(2.7)

____________________________

(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 September 30, 2020, we had $51.6 million of deferred tax assets, net of $446.4 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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Certain Provisions of the ENLK Partnership Agreement

9 Months Ended

Sep. 30, 2020

Partners' Capital [Abstract]

Certain Provisions of the ENLK Partnership Agreement

(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of September 30, 2020 and December 31, 2019, there were 60,047,665 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 nine months ended September 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
Third Quarter of 2020	150,119	$	16.9	November 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
Third Quarter of 2019	148,627	$	17.1	November 13, 2019

b.Series C Preferred Units

As of September 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 nine months ended September 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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Members' Equity

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Members' Equity

(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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Distributed earnings allocated to:
Common units (1)(2)	$	45.9	$	138.0	$	137.6	$	385.2
Unvested restricted units (1)(2)	0.7		1.6		2.3		4.6
Total distributed earnings	$	46.6	$	139.6	$	139.9	$	389.8
Undistributed loss allocated to:
Common units	$	(33.4)	$	(126.3)	$	(403.0)	$	(563.6)
Unvested restricted units	(0.6)		(1.5)		(7.0)		(6.8)
Total undistributed loss	$	(34.0)	$	(127.8)	$	(410.0)	$	(570.4)
Net income (loss) allocated to:
Common units	$	12.5	$	11.7	$	(265.4)	$	(178.4)
Unvested restricted units	0.1		0.1		(4.7)		(2.2)
Total net income (loss)	$	12.6	$	11.8	$	(270.1)	$	(180.6)
Basic and diluted net income (loss) per unit:
Basic	$	0.03	$	0.02	$	(0.55)	$	(0.40)
Diluted	$	0.03	$	0.02	$	(0.55)	$	(0.40)

____________________________

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

(2)For the nine months ended September 30, 2020, distributed earnings included a declared distribution of $0.09375 per unit payable on November 13, 2020, $0.09375 per unit paid on August 13, 2020, and $0.09375 per unit paid on May 13, 2020. For the nine months ended September 30, 2019, distributed earnings included distributions of $0.283 per unit paid on November 13, 2019, $0.283 per unit paid on August 13, 2019, and $0.279 per unit paid on May 14, 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 September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	489.7	487.4	489.2	455.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	489.7	487.4	489.2	455.9
Dilutive effect of non-vested restricted units (1)	1.2	2.0	—	—
Total weighted average diluted common units outstanding	490.9	489.4	489.2	455.9

____________________________

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

b.Distributions

A summary of our distribution activity relating to the ENLC common units for the nine months ended September 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
Third Quarter of 2020	$	0.09375	November 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
Third Quarter of 2019	$	0.283	November 13, 2019

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Investment in Unconsolidated Affiliates

9 Months Ended

Sep. 30, 2020

Equity Method Investments and Joint Ventures [Abstract]

Investment in Unconsolidated Affiliates

(9) Investment in Unconsolidated Affiliates

As of September 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
GCF
Distributions	$	—	$	5.1	$	1.6	$	14.7
Equity in income	$	0.4	$	4.4	$	2.5	$	15.3
Cedar Cove JV
Distributions	$	—	$	0.3	$	0.4	$	0.8
Equity in loss	$	(0.6)	$	(0.4)	$	(1.7)	$	(1.3)
Total
Distributions	$	—	$	5.4	$	2.0	$	15.5
Equity in income (loss)	$	(0.2)	$	4.0	$	0.8	$	14.0

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

	September 30, 2020		December 31, 2019
GCF	$	40.1	$	39.2
Cedar Cove JV	1.8		3.9
Total investment in unconsolidated affiliates	$	41.9	$	43.1

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Employee Incentive Plans

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement [Abstract]

Employee Incentive Plans

(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 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 and the Managing Member 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Cost of unit-based compensation charged to operating expense	$	2.0	$	2.1	$	6.2	$	4.5
Cost of unit-based compensation charged to general and administrative expense	6.4		10.0		18.4		26.7
Total unit-based compensation expense	$	8.4	$	12.1	$	24.6	$	31.2
Non-controlling interest in unit-based compensation	$	—	$	—	$	—	$	0.5
Amount of related income tax benefit recognized in net income (loss) (1)	$	2.0	$	2.8	$	5.8	$	7.2

____________________________

(1)For the three and nine months ended September 30, 2020, the amount of related income tax expense recognized in net income (loss) excluded $1.6 million and $6.0 million, respectively, related to book-to-tax differences recorded upon vesting of restricted units. For the three and nine months ended September 30, 2019, the amount of related income tax expense recognized in net income excluded $1.3 million for each period related to book-to-tax differences recorded upon vesting of restricted units.

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 nine months ended September 30, 2020 is provided below:

	Nine Months Ended September 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)	4,873,848		5.42
Vested (1)(2)	(2,839,869)		10.93
Forfeited	(661,623)		8.28
Non-vested, end of period	5,435,961		$	8.50
Aggregate intrinsic value, end of period (in millions)	$	12.8

____________________________

(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 1,009,546 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 nine months ended September 30, 2020 and 2019 is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Restricted Incentive Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	1.0	$	3.1	$	11.9	$	16.0
Fair value of units vested	$	6.0	$	5.8	$	31.0	$	18.9

As of September 30, 2020, there was $23.3 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 1.6 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:

	Nine Months Ended September 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	1,361,986		6.63
Vested (1)	(181,647)		30.31
Forfeited	(166,211)		11.01
Non-vested, end of period	2,331,984		$	8.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

____________________________

(1)Vested units included 69,052 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 nine months ended September 30, 2020 and 2019 is provided below (in millions).

	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Performance Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	—	$	1.6	$	0.9	$	3.4
Fair value of units vested	$	—	$	6.0	$	5.5	$	7.9

As of September 30, 2020, there was $12.3 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 1.5 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			July 2020
Grant-Date Fair Value	$	7.69		$	1.13		$	2.33
Beginning TSR price	$	6.13		$	1.25		$	2.52
Risk-free interest rate	1.62		%	0.42		%	0.17		%
Volatility factor	37.00		%	51.00		%	67.00		%

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Derivatives

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of interest rate swap	$	4.7	$	(1.8)	$	(10.4)	$	(15.3)
Tax benefit (expense)	(1.1)		0.5		2.4		4.1
Gain (loss) on designated cash flow hedge	$	3.6	$	(1.3)	$	(8.0)	$	(11.2)

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Interest expense (income)	$	4.6	$	(0.1)	$	9.6	$	(0.4)

We expect to recognize an additional $18.6 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

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

	September 30, 2020		December 31, 2019
Fair value of derivative liabilities—current	$	(18.5)	$	(5.6)
Fair value of derivative liabilities—long-term	(4.5)		(6.8)
Net fair value of interest rate swaps	$	(23.0)	$	(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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of derivatives	$	(2.2)	$	(0.5)	$	(8.0)	$	4.7
Realized gain (loss) on derivatives	(2.9)		8.0		(0.3)		11.5
Gain (loss) on derivative activity	$	(5.1)	$	7.5	$	(8.3)	$	16.2

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

	September 30, 2020		December 31, 2019
Fair value of derivative assets—current	$	9.6	$	12.9
Fair value of derivative assets—long-term	5.4		4.3
Fair value of derivative liabilities—current	(14.6)		(8.8)
Net fair value of commodity swaps	$	0.4	$	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 September 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022.

		September 30, 2020
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gallons	(161.6)	$	(8.5)
NGL (long contracts)	Swaps	Gallons	1.9	—
Natural gas (short contracts)	Swaps	MMBtu	(18.1)	(2.3)
Natural gas (long contracts)	Swaps	MMBtu	11.3	0.5
Crude and condensate (short contracts)	Swaps	MMbbls	(9.5)	8.5
Crude and condensate (long contracts)	Swaps	MMbbls	0.6	2.2
Total fair value of commodity swaps				$	0.4

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 $15.0 million as of September 30, 2020 would be reduced to $9.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

(12) Fair Value Measurements

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

	Level 2
	September 30, 2020		December 31, 2019
Interest rate swaps (1)	$	(23.0)	$	(12.4)
Commodity swaps (2)	$	0.4	$	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):

	September 30, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,650.0	$	3,892.8	$	4,764.3	$	4,444.2

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance costs of $26.4 million and $29.8 million as of September 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 September 30, 2020 and December 31, 2019 were based on Level 2 inputs from third-party market quotations.

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Segment Information

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Segment Information

(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;

•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;

•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;

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

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		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2020
Natural gas sales	$	46.5	$	76.4	$	40.1	$	16.0	$	—	$	179.0
NGL sales	0.1		402.3		1.2		—		—		403.6
Crude oil and condensate sales	82.6		21.7		9.2		—		—		113.5
Product sales	129.2		500.4		50.5		16.0		—		696.1
NGL sales—related parties	95.6		3.3		85.4		21.4		(205.7)		—
Crude oil and condensate sales—related parties	—		—		—		0.7		(0.7)		—
Product sales—related parties	95.6		3.3		85.4		22.1		(206.4)		—
Gathering and transportation	17.9		10.7		56.7		43.4		—		128.7
Processing	8.0		0.3		32.4		33.3		—		74.0
NGL services	—		14.2		—		—		—		14.2
Crude services	3.8		12.2		3.7		—		—		19.7
Other services	0.2		0.4		0.1		0.2		—		0.9
Midstream services	29.9		37.8		92.9		76.9		—		237.5
Crude services—related parties	—		—		0.1		—		(0.1)		—
Midstream services—related parties	—		—		0.1		—		(0.1)		—
Revenue from contracts with customers	254.7		541.5		228.9		115.0		(206.5)		933.6
Cost of sales	(185.4)		(441.4)		(101.0)		(28.2)		206.5		(549.5)
Operating expenses	(22.9)		(31.1)		(20.1)		(20.2)		—		(94.3)
Loss on derivative activity	—		—		—		—		(5.1)		(5.1)
Segment profit (loss)	$	46.4	$	69.0	$	107.8	$	66.6	$	(5.1)	$	284.7
Depreciation and amortization	$	(31.9)	$	(36.9)	$	(53.0)	$	(36.8)	$	(1.7)	$	(160.3)
Capital expenditures	$	28.5	$	8.5	$	2.6	$	3.0	$	0.6	$	43.2

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2019
Natural gas sales	$	24.3	$	92.0	$	54.6	$	22.2	$	—	$	193.1
NGL sales	0.3		421.0		4.6		6.0		—		431.9
Crude oil and condensate sales	409.4		74.6		28.2		—		—		512.2
Product sales	434.0		587.6		87.4		28.2		—		1,137.2
Natural gas sales—related parties	(0.1)		—		—		—		0.1		—
NGL sales—related parties	69.3		7.9		90.2		21.0		(188.4)		—
Crude oil and condensate sales—related parties	2.8		1.7		—		1.1		(5.6)		—
Product sales—related parties	72.0		9.6		90.2		22.1		(193.9)		—
Gathering and transportation	14.7		12.2		63.7		50.1		—		140.7
Processing	8.3		0.8		35.7		36.3		—		81.1
NGL services	—		11.2		—		—		—		11.2
Crude services	6.4		13.5		5.9		—		—		25.8
Other services	4.0		0.1		0.1		0.3		—		4.5
Midstream services	33.4		37.8		105.4		86.7		—		263.3
Crude services—related parties	—		—		0.2		—		(0.2)		—
Midstream services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	539.4		635.0		283.2		137.0		(194.1)		1,400.5
Cost of sales	(474.2)		(529.6)		(148.4)		(41.4)		194.1		(999.5)
Operating expenses	(28.9)		(38.4)		(25.7)		(26.2)		—		(119.2)
Gain on derivative activity	—		—		—		—		7.5		7.5
Segment profit	$	36.3	$	67.0	$	109.1	$	69.4	$	7.5	$	289.3
Depreciation and amortization	$	(31.6)	$	(37.3)	$	(51.1)	$	(35.4)	$	(1.9)	$	(157.3)
Goodwill	$	184.6	$	—	$	813.4	$	125.7	$	—	$	1,123.7
Capital expenditures	$	119.7	$	21.5	$	48.6	$	5.0	$	1.7	$	196.5

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2020
Natural gas sales	$	94.0	$	226.6	$	110.0	$	50.7	$	—	$	481.3
NGL sales	0.2		1,056.9		2.9		0.3		—		1,060.3
Crude oil and condensate sales	454.6		95.0		30.4		—		—		580.0
Product sales	548.8		1,378.5		143.3		51.0		—		2,121.6
NGL sales—related parties	201.0		13.3		209.0		52.5		(475.8)		—
Crude oil and condensate sales—related parties	0.1		—		(0.1)		2.6		(2.6)		—
Product sales—related parties	201.1		13.3		208.9		55.1		(478.4)		—
Gathering and transportation	47.3		33.9		165.5		133.5		—		380.2
Processing	19.8		1.6		97.8		101.7		—		220.9
NGL services	—		52.4		—		0.1		—		52.5
Crude services	13.0		33.8		12.6		—		—		59.4
Other services	1.0		1.2		0.3		0.7		—		3.2
Midstream services	81.1		122.9		276.2		236.0		—		716.2
Crude services—related parties	—		—		0.3		—		(0.3)		—
Midstream services—related parties	—		—		0.3		—		(0.3)		—
Revenue from contracts with customers	831.0		1,514.7		628.7		342.1		(478.7)		2,837.8
Cost of sales	(637.7)		(1,213.6)		(255.8)		(74.1)		478.7		(1,702.5)
Operating expenses	(71.1)		(90.4)		(62.4)		(59.2)		—		(283.1)
Loss on derivative activity	—		—		—		—		(8.3)		(8.3)
Segment profit (loss)	$	122.2	$	210.7	$	310.5	$	208.8	$	(8.3)	$	843.9
Depreciation and amortization	$	(92.1)	$	(109.3)	$	(163.7)	$	(110.4)	$	(5.8)	$	(481.3)
Impairments	$	(184.6)	$	(169.9)	$	—	$	—	$	—	$	(354.5)
Capital expenditures	$	161.4	$	39.3	$	14.1	$	10.7	$	1.7	$	227.2

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2019
Natural gas sales	$	59.4	$	316.8	$	176.5	$	104.7	$	—	$	657.4
NGL sales	0.9		1,492.9		17.8		24.0		—		1,535.6
Crude oil and condensate sales	1,622.2		216.9		86.4		—		—		1,925.5
Product sales	1,682.5		2,026.6		280.7		128.7		—		4,118.5
Natural gas sales—related parties	0.3		—		—		0.3		(0.6)		—
NGL sales—related parties	242.9		16.4		320.9		71.7		(651.9)		—
Crude oil and condensate sales—related parties	13.7		1.7		—		3.8		(19.2)		—
Product sales—related parties	256.9		18.1		320.9		75.8		(671.7)		—
Gathering and transportation	36.3		46.1		178.2		149.0		—		409.6
Processing	23.3		2.5		105.5		106.8		—		238.1
NGL services	—		32.9		—		—		—		32.9
Crude services	16.9		40.2		15.1		—		—		72.2
Other services	8.4		0.5		—		0.8		—		9.7
Midstream services	84.9		122.2		298.8		256.6		—		762.5
NGL services—related parties	—		(3.3)		—		—		3.3		—
Crude services—related parties	—		—		1.7		—		(1.7)		—
Midstream services—related parties	—		(3.3)		1.7		—		1.6		—
Revenue from contracts with customers	2,024.3		2,163.6		902.1		461.1		(670.1)		4,881.0
Cost of sales	(1,830.9)		(1,844.1)		(492.0)		(166.1)		670.1		(3,663.0)
Operating expenses	(85.1)		(111.6)		(77.2)		(77.7)		—		(351.6)
Gain on derivative activity	—		—		—		—		16.2		16.2
Segment profit	$	108.3	$	207.9	$	332.9	$	217.3	$	16.2	$	882.6
Depreciation and amortization	$	(89.6)	$	(116.0)	$	(144.8)	$	(106.6)	$	(6.1)	$	(463.1)
Impairments	$	—	$	(186.5)	$	—	$	—	$	—	$	(186.5)
Goodwill	$	184.6	$	—	$	813.4	$	125.7	$	—	$	1,123.7
Capital expenditures	$	268.0	$	82.0	$	227.1	$	36.3	$	5.7	$	619.1

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Segment profit	$	284.7	$	289.3	$	843.9	$	882.6
General and administrative expenses	(25.7)		(38.5)		(79.6)		(122.1)
Gain (loss) on disposition of assets	1.8		3.0		(2.8)		2.9
Depreciation and amortization	(160.3)		(157.3)		(481.3)		(463.1)
Impairments	—		—		(354.5)		(186.5)
Loss on secured term loan receivable	—		—		—		(52.9)
Operating income (loss)	$	100.5	$	96.5	$	(74.3)	$	60.9

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

Segment Identifiable Assets:	September 30, 2020		December 31, 2019
Permian	$	2,245.3	$	2,465.7
Louisiana	2,278.9		2,562.0
Oklahoma	2,889.1		3,035.0
North Texas	1,031.2		1,135.8
Corporate	222.7		137.3
Total identifiable assets	$	8,667.2	$	9,335.8

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Other Information

9 Months Ended

Sep. 30, 2020

Other Liabilities Disclosure [Abstract]

Other Information

(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:	September 30, 2020		December 31, 2019
Natural gas and NGLs inventory	$	63.9	$	43.4
Prepaid expenses and other	17.8		14.4
Other current assets	$	81.7	$	57.8

Other current liabilities:	September 30, 2020		December 31, 2019
Accrued interest	$	66.7	$	37.1
Accrued wages and benefits, including taxes	18.3		31.5
Accrued ad valorem taxes	33.9		28.5
Capital expenditure accruals	12.1		42.4
Retainage liability	11.8		8.7
Short-term lease liability	17.1		21.1
Suspense producer payments	10.3		13.8
Operating expense accruals	10.5		10.8
Other	18.1		12.3
Other current liabilities	$	198.8	$	206.2

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Subsequent Events

9 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

Subsequent Events

(15) Subsequent Events

Accounts Receivable Securitization Facility. On October 21, 2020 (the “Closing Date”), EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity (the “SPV”) that is an indirect subsidiary of ENLC entered into a three-year committed accounts receivable securitization facility (the “AR Facility”) of up to $250 million with PNC Bank, National Association, as administrative agent (the “Administrative Agent”) and lender, and PNC Capital Markets, LLC (“PNCCM”), as structuring agent.

In connection with the AR Facility, certain subsidiaries of ENLC, as originators (the “Originators”), have sold and contributed, and will continue to sell or contribute, pursuant to a Sale and Contribution Agreement, dated as of the Closing Date (the “Sale and Contribution Agreement”), all of their accounts receivable and certain related assets (collectively, the “Receivables”) to the SPV, a separate legal subsidiary of ENLC whose sole business consists of the purchase, or acceptance through capital contributions, of the Receivables and whose assets are not available to satisfy creditors of ENLC, the Originators, or any other subsidiary of ENLC.

The SPV financed its acquisition of the Receivables, and will finance its ongoing purchase of the Receivables, in part by obtaining secured loans from the lenders party to the Receivables Financing Agreement, dated as of the Closing Date (the “RFA”), among the SPV, EnLink Midstream Operating, LP, as initial servicer (the “Servicer”), the Administrative Agent, the lenders party thereto, and PNCCM. The amount available for borrowings at any one time under the RFA is limited to a borrowing base amount calculated based on the outstanding balance of eligible Receivables, subject to certain reserves,

concentration limits, and other limitations. Borrowings under the RFA bear interest based on LIBOR or LMIR (each as defined in the RFA), in each case subject to a minimum floor of 37.5 basis points, plus a drawn fee initially in the amount of 162.5 bps. The drawn fee varies based on ENLC’s credit rating, and the SPV also pays a fee on the undrawn committed amount of the RFA. Interest and fees payable by the SPV under the RFA are due monthly.

The SPV pledged its ownership interest in the Receivables as collateral security for all amounts outstanding under the RFA, and the Servicer will perform administrative and collection services relating to the Receivables on behalf of the SPV for a fee.

The RFA is scheduled to terminate on October 20, 2023, unless extended in accordance with its terms or earlier terminated, at which time no further advances will be available and the obligations thereunder repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the RFA become due and payable.

The purchase price for the sale of the Receivables by an Originator to the SPV consisted of, and will continue to consist of, a combination of (i) equity contributions in the SPV from its direct parent, (ii) cash available to the SPV from loans under the RFA and from collections on previously sold Receivables, and (iii) to the extent that the SPV does not have funds available to pay the purchase price in cash, through an increase in the principal amount of a subordinated intercompany loan deemed made by such Originator to the SPV.

ENLC guaranteed the respective obligations of the Originators and the Servicer under the Sale and Contribution Agreement and the RFA, as applicable, pursuant to a Performance Guaranty dated as of the Closing Date. However, neither ENLC nor any of its subsidiaries guarantees the SPV’s borrowings under the RFA or the collectability of the Receivables.

As of the Closing Date there were $225 million of borrowings by the SPV under the RFA. ENLC used the cash proceeds from the sale of the Receivables to the SPV to repay borrowings under its revolving credit facility.

Sale of Victoria Express Pipeline. On October 22, 2020, we completed the sale of the Victoria Express Pipeline and its related terminals and storage assets located in the Eagle Ford Shale in South Texas for approximately $20 million. We expect to recognize a loss of approximately $8 million on the sale.

Common Unit Repurchase Program. The board of directors of the Managing Member has authorized, effective immediately, a common unit repurchase program for the repurchase of up to $100 million of outstanding ENLC common units. The repurchases will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The repurchases will depend on market conditions and may be discontinued at any time.

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Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation

Basis of PresentationThe 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.

Revenue Recognition

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 nine months ended September 30, 2020, we had contractual commitments of $44.8 million and $128.0 million under our MVC contracts, respectively, and recorded $14.0 million and $39.2 million of revenue due to volume shortfalls, respectively.

Property and Equipment

Property and EquipmentImpairment 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.

Redeemable Non-Controlling Interest

Redeemable Non-Controlling InterestNon-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.

Adopted Accounting Standards

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 nine months ended September 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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Significant Accounting Polices (Tables)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

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 nine months ended September 30, 2020, we had contractual commitments of $44.8 million and $128.0 million under our MVC contracts, respectively, and recorded $14.0 million and $39.2 million of revenue due to volume shortfalls, respectively.

MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)	$	65.3
2021	119.7
2022	102.1
2023	91.5
2024	77.4
Thereafter	144.9
Total	$	600.9

____________________________

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

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Goodwill and Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of Changes in Carrying Value

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

	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Nine Months Ended September 30, 2020
Customer relationships, beginning of period	$	1,795.8	$	(545.9)	$	1,249.9
Amortization expense	—		(92.7)		(92.7)
Retirements (1)	(1.6)		0.6		(1.0)
Customer relationships, end of period	$	1,794.2	$	(638.0)	$	1,156.2

____________________________

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

Schedule of Amortization Expense

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

2020 (remaining)	$	30.8
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8
Total	$	1,156.2

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Summary of Debt

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

	September 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)	$	300.0	$	—	$	300.0	$	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		1.1		522.9		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		(5.7)		444.3		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	$	4,682.3	$	(5.9)	4,676.4		$	4,800.0	$	(5.9)	4,794.1
Debt issuance cost (3)					(26.4)						(29.8)
Long-term debt, net of unamortized issuance cost					$	4,650.0					$	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 September 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 September 30, 2020 and December 31, 2019, respectively.

(3)Net of amortization of $13.7 million and $10.9 million at September 30, 2020 and December 31, 2019, respectively.

For the nine months ended September 30, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. We and ENLK did not make any payments to repurchase senior notes during the three months ended September 30, 2020. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions):

	Nine Months Ended September 30, 2020
Debt repurchased	$	67.7
Aggregate payments	(36.0)
Net discount on repurchased debt	(0.3)
Accrued interest on repurchased debt	0.6
Gain on extinguishment of debt	$	32.0

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Current income tax expense	$	(0.4)	$	(0.7)	$	(1.1)	$	(2.0)
Deferred income tax benefit (expense)	(5.6)		(5.6)		17.1		(0.7)
Income tax benefit (expense)	$	(6.0)	$	(6.3)	$	16.0	$	(2.7)

Reconciliation of Total Income Tax Expense to Income before Income Taxes

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Expected income tax benefit (expense) based on federal statutory rate	$	(3.6)	$	(3.8)	$	60.0	$	37.4
State income tax benefit (expense), net of federal benefit	(0.6)		(0.7)		6.4		3.6
Unit-based compensation (1)	(1.6)		(1.3)		(6.0)		(1.3)
Non-deductible expense related to goodwill impairment	—		—		(43.4)		(43.8)
Other	(0.2)		(0.5)		(1.0)		1.4
Income tax benefit (expense)	$	(6.0)	$	(6.3)	$	16.0	$	(2.7)

____________________________

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

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Certain Provisions of the ENLK Partnership Agreement (Tables)

9 Months Ended

Sep. 30, 2020

Partners' Capital [Abstract]

Summary of Distribution Activity

A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 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
Third Quarter of 2020	150,119	$	16.9	November 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
Third Quarter of 2019	148,627	$	17.1	November 13, 2019

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Members' Equity (Tables)

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Limited Partner Unit

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Distributed earnings allocated to:
Common units (1)(2)	$	45.9	$	138.0	$	137.6	$	385.2
Unvested restricted units (1)(2)	0.7		1.6		2.3		4.6
Total distributed earnings	$	46.6	$	139.6	$	139.9	$	389.8
Undistributed loss allocated to:
Common units	$	(33.4)	$	(126.3)	$	(403.0)	$	(563.6)
Unvested restricted units	(0.6)		(1.5)		(7.0)		(6.8)
Total undistributed loss	$	(34.0)	$	(127.8)	$	(410.0)	$	(570.4)
Net income (loss) allocated to:
Common units	$	12.5	$	11.7	$	(265.4)	$	(178.4)
Unvested restricted units	0.1		0.1		(4.7)		(2.2)
Total net income (loss)	$	12.6	$	11.8	$	(270.1)	$	(180.6)
Basic and diluted net income (loss) per unit:
Basic	$	0.03	$	0.02	$	(0.55)	$	(0.40)
Diluted	$	0.03	$	0.02	$	(0.55)	$	(0.40)

____________________________

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

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

Schedule of Unit Amounts Used to Computer Earnings per Unit

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 September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	489.7	487.4	489.2	455.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	489.7	487.4	489.2	455.9
Dilutive effect of non-vested restricted units (1)	1.2	2.0	—	—
Total weighted average diluted common units outstanding	490.9	489.4	489.2	455.9

____________________________

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

Summary of Distribution Activity

A summary of our distribution activity relating to the ENLC common units for the nine months ended September 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
Third Quarter of 2020	$	0.09375	November 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
Third Quarter of 2019	$	0.283	November 13, 2019

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Investment in Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2020

Equity Method Investments and Joint Ventures [Abstract]

Activity Related to Investment in Unconsolidated Affiliates

The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
GCF
Distributions	$	—	$	5.1	$	1.6	$	14.7
Equity in income	$	0.4	$	4.4	$	2.5	$	15.3
Cedar Cove JV
Distributions	$	—	$	0.3	$	0.4	$	0.8
Equity in loss	$	(0.6)	$	(0.4)	$	(1.7)	$	(1.3)
Total
Distributions	$	—	$	5.4	$	2.0	$	15.5
Equity in income (loss)	$	(0.2)	$	4.0	$	0.8	$	14.0

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

	September 30, 2020		December 31, 2019
GCF	$	40.1	$	39.2
Cedar Cove JV	1.8		3.9
Total investment in unconsolidated affiliates	$	41.9	$	43.1

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Employee Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement [Abstract]

Schedule of Amounts Recognized in Consolidated Financial Statements

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Cost of unit-based compensation charged to operating expense	$	2.0	$	2.1	$	6.2	$	4.5
Cost of unit-based compensation charged to general and administrative expense	6.4		10.0		18.4		26.7
Total unit-based compensation expense	$	8.4	$	12.1	$	24.6	$	31.2
Non-controlling interest in unit-based compensation	$	—	$	—	$	—	$	0.5
Amount of related income tax benefit recognized in net income (loss) (1)	$	2.0	$	2.8	$	5.8	$	7.2

____________________________

(1)For the three and nine months ended September 30, 2020, the amount of related income tax expense recognized in net income (loss) excluded $1.6 million and $6.0 million, respectively, related to book-to-tax differences recorded upon vesting of restricted units. For the three and nine months ended September 30, 2019, the amount of related income tax expense recognized in net income excluded $1.3 million for each period related to book-to-tax differences recorded upon vesting of restricted units.

Schedule Of Restricted Stock Units Activity, ENLC

A summary of the restricted incentive unit activity for the nine months ended September 30, 2020 is provided below:

	Nine Months Ended September 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)	4,873,848		5.42
Vested (1)(2)	(2,839,869)		10.93
Forfeited	(661,623)		8.28
Non-vested, end of period	5,435,961		$	8.50
Aggregate intrinsic value, end of period (in millions)	$	12.8

____________________________

(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 1,009,546 units withheld for payroll taxes paid on behalf of employees.

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units, Vested and Fair Value Vested, ENLC

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 nine months ended September 30, 2020 and 2019 is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Restricted Incentive Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	1.0	$	3.1	$	11.9	$	16.0
Fair value of units vested	$	6.0	$	5.8	$	31.0	$	18.9

Summary of Performance Units, ENLC

The following table presents a summary of the performance units:

	Nine Months Ended September 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	1,361,986		6.63
Vested (1)	(181,647)		30.31
Forfeited	(166,211)		11.01
Non-vested, end of period	2,331,984		$	8.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

____________________________

(1)Vested units included 69,052 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 nine months ended September 30, 2020 and 2019 is provided below (in millions).

	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Performance Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	—	$	1.6	$	0.9	$	3.4
Fair value of units vested	$	—	$	6.0	$	5.5	$	7.9

Summary of Grant-Date Fair Values

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			July 2020
Grant-Date Fair Value	$	7.69		$	1.13		$	2.33
Beginning TSR price	$	6.13		$	1.25		$	2.52
Risk-free interest rate	1.62		%	0.42		%	0.17		%
Volatility factor	37.00		%	51.00		%	67.00		%

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Components of Gain (Loss) on Derivative Activity

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of interest rate swap	$	4.7	$	(1.8)	$	(10.4)	$	(15.3)
Tax benefit (expense)	(1.1)		0.5		2.4		4.1
Gain (loss) on designated cash flow hedge	$	3.6	$	(1.3)	$	(8.0)	$	(11.2)

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Interest expense (income)	$	4.6	$	(0.1)	$	9.6	$	(0.4)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of derivatives	$	(2.2)	$	(0.5)	$	(8.0)	$	4.7
Realized gain (loss) on derivatives	(2.9)		8.0		(0.3)		11.5
Gain (loss) on derivative activity	$	(5.1)	$	7.5	$	(8.3)	$	16.2

Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps

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

	September 30, 2020		December 31, 2019
Fair value of derivative liabilities—current	$	(18.5)	$	(5.6)
Fair value of derivative liabilities—long-term	(4.5)		(6.8)
Net fair value of interest rate swaps	$	(23.0)	$	(12.4)

Schedule Of Fair Value of Derivative Assets and Liabilities Related To Commodity Swaps

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

	September 30, 2020		December 31, 2019
Fair value of derivative assets—current	$	9.6	$	12.9
Fair value of derivative assets—long-term	5.4		4.3
Fair value of derivative liabilities—current	(14.6)		(8.8)
Net fair value of commodity swaps	$	0.4	$	8.4

Notional Amount and Fair Value of Derivative Instruments

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 September 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022.

		September 30, 2020
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gallons	(161.6)	$	(8.5)
NGL (long contracts)	Swaps	Gallons	1.9	—
Natural gas (short contracts)	Swaps	MMBtu	(18.1)	(2.3)
Natural gas (long contracts)	Swaps	MMBtu	11.3	0.5
Crude and condensate (short contracts)	Swaps	MMbbls	(9.5)	8.5
Crude and condensate (long contracts)	Swaps	MMbbls	0.6	2.2
Total fair value of commodity swaps				$	0.4

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Schedule of Net Assets (Liabilities) Measured on a Recurring Basis

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

	Level 2
	September 30, 2020		December 31, 2019
Interest rate swaps (1)	$	(23.0)	$	(12.4)
Commodity swaps (2)	$	0.4	$	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.

Schedule of the Estimated Fair Value of Financial Instruments

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):

	September 30, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,650.0	$	3,892.8	$	4,764.3	$	4,444.2

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance costs of $26.4 million and $29.8 million as of September 30, 2020 and December 31, 2019, respectively. The respective fair values do not factor in debt issuance costs.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Summary of Financial Information

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		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2020
Natural gas sales	$	46.5	$	76.4	$	40.1	$	16.0	$	—	$	179.0
NGL sales	0.1		402.3		1.2		—		—		403.6
Crude oil and condensate sales	82.6		21.7		9.2		—		—		113.5
Product sales	129.2		500.4		50.5		16.0		—		696.1
NGL sales—related parties	95.6		3.3		85.4		21.4		(205.7)		—
Crude oil and condensate sales—related parties	—		—		—		0.7		(0.7)		—
Product sales—related parties	95.6		3.3		85.4		22.1		(206.4)		—
Gathering and transportation	17.9		10.7		56.7		43.4		—		128.7
Processing	8.0		0.3		32.4		33.3		—		74.0
NGL services	—		14.2		—		—		—		14.2
Crude services	3.8		12.2		3.7		—		—		19.7
Other services	0.2		0.4		0.1		0.2		—		0.9
Midstream services	29.9		37.8		92.9		76.9		—		237.5
Crude services—related parties	—		—		0.1		—		(0.1)		—
Midstream services—related parties	—		—		0.1		—		(0.1)		—
Revenue from contracts with customers	254.7		541.5		228.9		115.0		(206.5)		933.6
Cost of sales	(185.4)		(441.4)		(101.0)		(28.2)		206.5		(549.5)
Operating expenses	(22.9)		(31.1)		(20.1)		(20.2)		—		(94.3)
Loss on derivative activity	—		—		—		—		(5.1)		(5.1)
Segment profit (loss)	$	46.4	$	69.0	$	107.8	$	66.6	$	(5.1)	$	284.7
Depreciation and amortization	$	(31.9)	$	(36.9)	$	(53.0)	$	(36.8)	$	(1.7)	$	(160.3)
Capital expenditures	$	28.5	$	8.5	$	2.6	$	3.0	$	0.6	$	43.2

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2019
Natural gas sales	$	24.3	$	92.0	$	54.6	$	22.2	$	—	$	193.1
NGL sales	0.3		421.0		4.6		6.0		—		431.9
Crude oil and condensate sales	409.4		74.6		28.2		—		—		512.2
Product sales	434.0		587.6		87.4		28.2		—		1,137.2
Natural gas sales—related parties	(0.1)		—		—		—		0.1		—
NGL sales—related parties	69.3		7.9		90.2		21.0		(188.4)		—
Crude oil and condensate sales—related parties	2.8		1.7		—		1.1		(5.6)		—
Product sales—related parties	72.0		9.6		90.2		22.1		(193.9)		—
Gathering and transportation	14.7		12.2		63.7		50.1		—		140.7
Processing	8.3		0.8		35.7		36.3		—		81.1
NGL services	—		11.2		—		—		—		11.2
Crude services	6.4		13.5		5.9		—		—		25.8
Other services	4.0		0.1		0.1		0.3		—		4.5
Midstream services	33.4		37.8		105.4		86.7		—		263.3
Crude services—related parties	—		—		0.2		—		(0.2)		—
Midstream services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	539.4		635.0		283.2		137.0		(194.1)		1,400.5
Cost of sales	(474.2)		(529.6)		(148.4)		(41.4)		194.1		(999.5)
Operating expenses	(28.9)		(38.4)		(25.7)		(26.2)		—		(119.2)
Gain on derivative activity	—		—		—		—		7.5		7.5
Segment profit	$	36.3	$	67.0	$	109.1	$	69.4	$	7.5	$	289.3
Depreciation and amortization	$	(31.6)	$	(37.3)	$	(51.1)	$	(35.4)	$	(1.9)	$	(157.3)
Goodwill	$	184.6	$	—	$	813.4	$	125.7	$	—	$	1,123.7
Capital expenditures	$	119.7	$	21.5	$	48.6	$	5.0	$	1.7	$	196.5

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2020
Natural gas sales	$	94.0	$	226.6	$	110.0	$	50.7	$	—	$	481.3
NGL sales	0.2		1,056.9		2.9		0.3		—		1,060.3
Crude oil and condensate sales	454.6		95.0		30.4		—		—		580.0
Product sales	548.8		1,378.5		143.3		51.0		—		2,121.6
NGL sales—related parties	201.0		13.3		209.0		52.5		(475.8)		—
Crude oil and condensate sales—related parties	0.1		—		(0.1)		2.6		(2.6)		—
Product sales—related parties	201.1		13.3		208.9		55.1		(478.4)		—
Gathering and transportation	47.3		33.9		165.5		133.5		—		380.2
Processing	19.8		1.6		97.8		101.7		—		220.9
NGL services	—		52.4		—		0.1		—		52.5
Crude services	13.0		33.8		12.6		—		—		59.4
Other services	1.0		1.2		0.3		0.7		—		3.2
Midstream services	81.1		122.9		276.2		236.0		—		716.2
Crude services—related parties	—		—		0.3		—		(0.3)		—
Midstream services—related parties	—		—		0.3		—		(0.3)		—
Revenue from contracts with customers	831.0		1,514.7		628.7		342.1		(478.7)		2,837.8
Cost of sales	(637.7)		(1,213.6)		(255.8)		(74.1)		478.7		(1,702.5)
Operating expenses	(71.1)		(90.4)		(62.4)		(59.2)		—		(283.1)
Loss on derivative activity	—		—		—		—		(8.3)		(8.3)
Segment profit (loss)	$	122.2	$	210.7	$	310.5	$	208.8	$	(8.3)	$	843.9
Depreciation and amortization	$	(92.1)	$	(109.3)	$	(163.7)	$	(110.4)	$	(5.8)	$	(481.3)
Impairments	$	(184.6)	$	(169.9)	$	—	$	—	$	—	$	(354.5)
Capital expenditures	$	161.4	$	39.3	$	14.1	$	10.7	$	1.7	$	227.2

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2019
Natural gas sales	$	59.4	$	316.8	$	176.5	$	104.7	$	—	$	657.4
NGL sales	0.9		1,492.9		17.8		24.0		—		1,535.6
Crude oil and condensate sales	1,622.2		216.9		86.4		—		—		1,925.5
Product sales	1,682.5		2,026.6		280.7		128.7		—		4,118.5
Natural gas sales—related parties	0.3		—		—		0.3		(0.6)		—
NGL sales—related parties	242.9		16.4		320.9		71.7		(651.9)		—
Crude oil and condensate sales—related parties	13.7		1.7		—		3.8		(19.2)		—
Product sales—related parties	256.9		18.1		320.9		75.8		(671.7)		—
Gathering and transportation	36.3		46.1		178.2		149.0		—		409.6
Processing	23.3		2.5		105.5		106.8		—		238.1
NGL services	—		32.9		—		—		—		32.9
Crude services	16.9		40.2		15.1		—		—		72.2
Other services	8.4		0.5		—		0.8		—		9.7
Midstream services	84.9		122.2		298.8		256.6		—		762.5
NGL services—related parties	—		(3.3)		—		—		3.3		—
Crude services—related parties	—		—		1.7		—		(1.7)		—
Midstream services—related parties	—		(3.3)		1.7		—		1.6		—
Revenue from contracts with customers	2,024.3		2,163.6		902.1		461.1		(670.1)		4,881.0
Cost of sales	(1,830.9)		(1,844.1)		(492.0)		(166.1)		670.1		(3,663.0)
Operating expenses	(85.1)		(111.6)		(77.2)		(77.7)		—		(351.6)
Gain on derivative activity	—		—		—		—		16.2		16.2
Segment profit	$	108.3	$	207.9	$	332.9	$	217.3	$	16.2	$	882.6
Depreciation and amortization	$	(89.6)	$	(116.0)	$	(144.8)	$	(106.6)	$	(6.1)	$	(463.1)
Impairments	$	—	$	(186.5)	$	—	$	—	$	—	$	(186.5)
Goodwill	$	184.6	$	—	$	813.4	$	125.7	$	—	$	1,123.7
Capital expenditures	$	268.0	$	82.0	$	227.1	$	36.3	$	5.7	$	619.1

Reconciliation of Profits to Operating Income (Loss)

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Segment profit	$	284.7	$	289.3	$	843.9	$	882.6
General and administrative expenses	(25.7)		(38.5)		(79.6)		(122.1)
Gain (loss) on disposition of assets	1.8		3.0		(2.8)		2.9
Depreciation and amortization	(160.3)		(157.3)		(481.3)		(463.1)
Impairments	—		—		(354.5)		(186.5)
Loss on secured term loan receivable	—		—		—		(52.9)
Operating income (loss)	$	100.5	$	96.5	$	(74.3)	$	60.9

Schedule of Segment Assets

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

Segment Identifiable Assets:	September 30, 2020		December 31, 2019
Permian	$	2,245.3	$	2,465.7
Louisiana	2,278.9		2,562.0
Oklahoma	2,889.1		3,035.0
North Texas	1,031.2		1,135.8
Corporate	222.7		137.3
Total identifiable assets	$	8,667.2	$	9,335.8

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Other Information (Tables)

9 Months Ended

Sep. 30, 2020

Other Liabilities Disclosure [Abstract]

Schedule of Other Current Liabilities

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

Other current assets:	September 30, 2020		December 31, 2019
Natural gas and NGLs inventory	$	63.9	$	43.4
Prepaid expenses and other	17.8		14.4
Other current assets	$	81.7	$	57.8

Other current liabilities:	September 30, 2020		December 31, 2019
Accrued interest	$	66.7	$	37.1
Accrued wages and benefits, including taxes	18.3		31.5
Accrued ad valorem taxes	33.9		28.5
Capital expenditure accruals	12.1		42.4
Retainage liability	11.8		8.7
Short-term lease liability	17.1		21.1
Suspense producer payments	10.3		13.8
Operating expense accruals	10.5		10.8
Other	18.1		12.3
Other current liabilities	$	198.8	$	206.2

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Significant Accounting Policies - Narrative (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020	Sep. 30, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charges		$ 1,900,000
Redemption of non-controlling interest		(4,000,000.0)	$ 0
Redeemable Non-Controlling Interest (Temporary Equity)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Redemption of non-controlling interest		4,000,000.0
Louisiana
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charges	$ 0	168,000,000.0
Minimum Volume Contract
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract with customer, liability	44,800,000	128,000,000.0
Contracts with customers, revenue recognition	$ 14,000,000.0	$ 39,200,000

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Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Sep. 30, 2020 USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 600.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 65.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 119.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 102.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 91.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 77.4
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 144.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period

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Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 30.9	$ 30.9		$ 92.7	$ 92.8
Operating Segments | Permian
Finite-Lived Intangible Assets [Line Items]
Goodwill, impairment loss				$ 184.6
Operating Segments | Louisiana
Finite-Lived Intangible Assets [Line Items]
Goodwill, impairment loss			$ 186.5
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets				10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets				20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets				15 years

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Goodwill and Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning Balance			$ (545.9)
Amortization expense	$ (30.9)	$ (30.9)	(92.7)	$ (92.8)
Retirements, net			(1.0)
Accumulated Amortization, Ending Balance	(638.0)		(638.0)
Net Carrying Amount, Ending Balance	1,156.2		1,156.2
Customer relationships
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance			1,795.8
Accumulated Amortization, Beginning Balance			(545.9)
Net Carrying Amount, Beginning Balance			1,249.9
Amortization expense			(92.7)
Retirements, gross			(1.6)
Retirements, accumulated amortization			0.6
Gross Carrying Amount, Ending Balance	1,794.2		1,794.2
Accumulated Amortization, Ending Balance	(638.0)		(638.0)
Net Carrying Amount, Ending Balance	$ 1,156.2		$ 1,156.2

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Goodwill and Intangible Assets - Amortization Expense (Details) $ in Millions	Sep. 30, 2020 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2020 (remaining)	$ 30.8
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8
Total	$ 1,156.2

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Related Party Transactions (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Related Party Transaction [Line Items]
Cost of sales	$ 549,500,000	$ 999,500,000	$ 1,702,500,000	$ 3,663,000,000.0
Accounts payable to related party	900,000		900,000		$ 1,100,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales	2,000,000.0	4,100,000	6,200,000	18,000,000.0
Accounts payable to related party	900,000		900,000		$ 1,100,000
GIP
Related Party Transaction [Line Items]
General and administrative expenses from transactions with related party	$ 200,000	$ 0	$ 200,000	$ 0

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Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Debt Instrument
Outstanding principal	$ 4,682.3	$ 4,800.0
Premium (discount)	(5.9)	(5.9)
Long-term debt	4,676.4	4,794.1
Debt issuance costs	(26.4)	(29.8)
Long-term debt, net of unamortized issuance cost	4,650.0	4,764.3
Debt issuance cost accumulated amortization	13.7	10.9
Consolidated Credit Facility due 2024
Debt Instrument
Outstanding principal	300.0	350.0
Premium (discount)	0.0	0.0
Long-term debt	$ 300.0	$ 350.0
Effective interest rate	1.80%	3.30%
Term Loan Due 2021
Debt Instrument
Outstanding principal	$ 850.0	$ 850.0
Premium (discount)	0.0	0.0
Long-term debt	$ 850.0	$ 850.0
Effective interest rate	1.70%	3.20%
4.4% Senior Notes Due 2024
Debt Instrument
Outstanding principal	$ 521.8	$ 550.0
Premium (discount)	1.1	1.5
Long-term debt	$ 522.9	551.5
Stated interest rate	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding principal	$ 720.8	750.0
Premium (discount)	(0.6)	(0.7)
Long-term debt	$ 720.2	749.3
Stated interest rate	4.15%
4.85 Senior Notes Due 2026
Debt Instrument
Outstanding principal	$ 491.0	500.0
Premium (discount)	(0.4)	(0.5)
Long-term debt	$ 490.6	499.5
Stated interest rate	4.85%
5.375% Senior Notes Due 2029
Debt Instrument
Outstanding principal	$ 498.7	500.0
Premium (discount)	0.0	0.0
Long-term debt	$ 498.7	500.0
Stated interest rate	5.375%
5.6% Senior Notes Due 2044
Debt Instrument
Outstanding principal	$ 350.0	350.0
Premium (discount)	(0.2)	(0.2)
Long-term debt	$ 349.8	349.8
Stated interest rate	5.60%
5.05 Senior Notes Due 2045
Debt Instrument
Outstanding principal	$ 450.0	450.0
Premium (discount)	(5.7)	(5.9)
Long-term debt	$ 444.3	444.1
Stated interest rate	5.05%
Senior Notes, 5.45%, Due 2047
Debt Instrument
Outstanding principal	$ 500.0	500.0
Premium (discount)	(0.1)	(0.1)
Long-term debt	$ 499.9	$ 499.9
Stated interest rate	5.45%

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Long-Term Debt - Narrative (Details)		9 Months Ended
	Dec. 11, 2018 USD ($)	Sep. 30, 2020 USD ($)
Letters of credit
Debt Instrument
Additional amount available (not to exceed)		$ 1,750,000,000
Maximum borrowing capacity		2,250,000,000
Line of credit facility, fair value of amount outstanding		300,000,000.0
Term Loan Due 2021
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5.0
Maximum | Term Loan Due 2021
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5.5
Conditional acquisition purchase price (or more)	$ 50,000,000.0
Letter of Credit | Letters of credit
Debt Instrument
Maximum borrowing capacity		$ 500,000,000.0
Debt instrument, covenant, percentage of letter of credits guaranteed		105.00%
Unsecured Debt | Letters of credit
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio		2.5
Ratio of consolidated indebtedness to consolidated EBITDA		5.0
Line of credit facility, consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio		5.5
Unsecured Debt | Term Loan Due 2021
Debt Instrument
Face amount		$ 850,000,000.0
Unsecured Debt | Minimum | Letters of credit
Debt Instrument
Conditional acquisition purchase price (or more)		$ 50,000,000.0
Unsecured Debt | LIBOR | Minimum | Letters of credit
Debt Instrument
Variable rate		1.125%
Unsecured Debt | LIBOR | Maximum | Letters of credit
Debt Instrument
Variable rate		2.00%
Unsecured Debt | Federal Funds | Letters of credit
Debt Instrument
Variable rate		0.50%
Unsecured Debt | Eurodollar | Letters of credit
Debt Instrument
Variable rate		1.00%
Unsecured Debt | Eurodollar | Minimum | Letters of credit
Debt Instrument
Variable rate		0.125%
Unsecured Debt | Eurodollar | Maximum | Letters of credit
Debt Instrument
Variable rate		1.00%
Line of Credit | Term Loan Due 2021
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio	2.5
Line of Credit | LIBOR | Minimum | Term Loan Due 2021
Debt Instrument
Variable rate	1.00%
Line of Credit | LIBOR | Maximum | Term Loan Due 2021
Debt Instrument
Variable rate	1.75%
Line of Credit | Federal Funds | Term Loan Due 2021
Debt Instrument
Variable rate	0.50%
Line of Credit | Eurodollar | Term Loan Due 2021
Debt Instrument
Variable rate	1.00%
Line of Credit | Eurodollar | Minimum | Term Loan Due 2021
Debt Instrument
Variable rate	0.00%
Line of Credit | Eurodollar | Maximum | Term Loan Due 2021
Debt Instrument
Variable rate	0.75%
ENLC | Letter of Credit | Letters of credit
Debt Instrument
Line of credit facility, fair value of amount outstanding		$ 19,300,000

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Long-Term Debt - Senior Unsecured Notes Repurchases (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
Debt Disclosure [Abstract]
Debt repurchased	$ 67.7
Aggregate payments	(36.0)
Net discount on repurchased debt	(0.3)
Accrued interest on repurchased debt	0.6
Gain on extinguishment of debt	$ 32.0

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Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.4)	$ (0.7)	$ (1.1)	$ (2.0)
Deferred income tax benefit (expense)	(5.6)	(5.6)	17.1	(0.7)
Income tax benefit (expense)	(6.0)	(6.3)	16.0	(2.7)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit (expense) based on federal statutory rate	(3.6)	(3.8)	60.0	37.4
State income tax benefit (expense), net of federal benefit	(0.6)	(0.7)	6.4	3.6
Unit-based compensation	(1.6)	(1.3)	(6.0)	(1.3)
Non-deductible expense related to goodwill impairment	0.0	0.0	(43.4)	(43.8)
Other	(0.2)	(0.5)	(1.0)	1.4
Income tax benefit (expense)	$ (6.0)	$ (6.3)	$ 16.0	$ (2.7)

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 51.6	$ 32.2
Deferred tax liabilities	$ (446.4)	$ (354.0)

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Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended								9 Months Ended
	Feb. 13, 2019	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Sep. 30, 2019
Partnership agreement
Distribution declared/unit (in dollars per share)		$ 0.09375	$ 0.09375	$ 0.09375	$ 0.1875	$ 0.283	$ 0.283	$ 0.279	$ 0.275
Series B Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)		150,119	149,745	149,371	148,999	148,627	148,257	147,887	425,785
Cash distributions		$ 16.9	$ 16.8	$ 16.8	$ 16.8	$ 17.1	$ 17.1	$ 16.7	$ 16.5
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		60,047,665			59,599,550					60,047,665
Preferred units, outstanding (in shares)		60,047,665			59,599,550					60,047,665
Series C Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)		12,000,000.0				12,000,000.0				12,000,000.0	12,000,000.0
Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		400,000			400,000					400,000
Preferred units, outstanding (in shares)		400,000			400,000					400,000
Common units | EnLink Midstream Partners, LP
Partnership agreement
Distribution declared/unit (in dollars per share)	$ 0.39

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Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions							3 Months Ended								9 Months Ended
	Nov. 13, 2020	Aug. 13, 2020	May 13, 2020	Nov. 13, 2019	Aug. 13, 2019	May 14, 2019	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Sep. 30, 2019
Distributed earnings allocated to:
Total distributed earnings							$ 46.6				$ 139.6				$ 139.9	$ 389.8
Undistributed loss allocated to:
Total undistributed loss							(34.0)				(127.8)				(410.0)	(570.4)
Net income (loss) allocated to:
Total net income (loss)							$ 12.6				$ 11.8				$ (270.1)	$ (180.6)
Basic and diluted net income (loss) per unit:
Basic (in dollars per share)							$ 0.03				$ 0.02				$ (0.55)	$ (0.40)
Diluted (in dollars per share)							0.03				0.02				$ (0.55)	$ (0.40)
Distribution declared/unit (in dollars per share)							$ 0.09375	$ 0.09375	$ 0.09375	$ 0.1875	$ 0.283	$ 0.283	$ 0.279	$ 0.275
Distribution paid per unit (in dollars per share)		$ 0.09375	$ 0.09375	$ 0.283	$ 0.283	$ 0.279
Subsequent Event
Basic and diluted net income (loss) per unit:
Distribution declared/unit (in dollars per share)	$ 0.09375
Distribution paid per unit (in dollars per share)	$ 0.09375
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings							$ 0.7				$ 1.6				$ 2.3	$ 4.6
Undistributed loss allocated to:
Total undistributed loss							(0.6)				(1.5)				(7.0)	(6.8)
Net income (loss) allocated to:
Total net income (loss)							0.1				0.1				(4.7)	(2.2)
Common units
Distributed earnings allocated to:
Total distributed earnings							45.9				138.0				137.6	385.2
Undistributed loss allocated to:
Total undistributed loss							(33.4)				(126.3)				(403.0)	(563.6)
Net income (loss) allocated to:
Total net income (loss)							$ 12.5				$ 11.7				$ (265.4)	$ (178.4)

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Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Basic weighted average units outstanding:
Weighted average basic and diluted common units outstanding (in shares)	489.7	487.4	489.2	455.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding (in units)	489.7	487.4	489.2	455.9
Dilutive effect of non-vested restricted units (in units)	1.2	2.0	0.0	0.0
Total weighted average diluted common units outstanding (in units)	490.9	489.4	489.2	455.9

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Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Equity method investments
Distributions	$ 0.0	$ 5.4	$ 2.0	$ 15.5
Equity in income (loss)	(0.2)	4.0	0.8	14.0
Total investment in unconsolidated affiliates	$ 41.9		$ 41.9		$ 43.1
GCF
Equity method investments
Ownership interest	38.75%		38.75%
Distributions	$ 0.0	5.1	$ 1.6	14.7
Equity in income (loss)	$ 0.4	4.4	$ 2.5	15.3
Cedar Cove JV
Equity method investments
Ownership interest	30.00%		30.00%
Distributions	$ 0.0	0.3	$ 0.4	0.8
Equity in income (loss)	(0.6)	$ (0.4)	(1.7)	$ (1.3)
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	41.9		41.9		43.1
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	40.1		40.1		39.2
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	$ 1.8		$ 1.8		$ 3.9

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Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Allocation
Compensation expense	$ 8.4	$ 12.1	$ 24.6	$ 31.2
Amount of related income tax benefit recognized in net income (loss)	2.0	2.8	5.8	7.2
Restricted units
Allocation
Amount of related income tax benefit recognized in net income (loss)	(1.6)	(1.3)	(6.0)	(1.3)
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	2.0	2.1	6.2	4.5
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	6.4	10.0	18.4	26.7
Non-controlling interest in unit-based compensation
Allocation
Compensation expense	$ 0.0	$ 0.0	$ 0.0	$ 0.5

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Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended				3 Months Ended		9 Months Ended
	Jul. 31, 2020	Mar. 31, 2020	Feb. 29, 2020	Jan. 31, 2020	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-Date Fair Value (in dollars per share)	$ 2.33	$ 1.13		$ 7.69
Beginning TSR Price (in dollars per share)	$ 2.52	$ 1.25		$ 6.13
Risk-free interest rate	0.17%	0.42%		1.62%
Volatility factor	67.00%	51.00%		37.00%
Unvested restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)				4,063,605			4,063,605
Granted (in shares)			1,144,842				4,873,848
Vested (in shares)							(2,839,869)
Forfeited (in shares)							(661,623)
Non-vested, end of period (in shares)					5,435,961		5,435,961
Aggregate intrinsic value, end of period					$ 12.8		$ 12.8
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)				$ 13.85			$ 13.85
Granted (in dollars per share)							5.42
Vested (in dollars per share)							10.93
Forfeited (in dollars per share)							8.28
Non-vested, end of period (in dollars per share)					$ 8.50		$ 8.50
Incentive unit award vesting period							3 years
Fair value of units vested			$ 5.2
Units withheld for payroll taxes (in shares)							1,009,546
Unrecognized compensation cost related to non-vested restricted incentive units					$ 23.3		$ 23.3
Unrecognized compensation costs, weighted average period for recognition							1 year 7 months 6 days
Unvested restricted units | ENLC
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Fair value of units vested					6.0	$ 5.8	$ 31.0	$ 18.9
Aggregate intrinsic value of units vested					$ 1.0	3.1	$ 11.9	16.0
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)				1,317,856			1,317,856
Granted (in shares)							1,361,986
Vested (in shares)							(181,647)
Forfeited (in shares)							(166,211)
Non-vested, end of period (in shares)					2,331,984		2,331,984
Aggregate intrinsic value, end of period					$ 5.5		$ 5.5
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)				$ 14.22			$ 14.22
Granted (in dollars per share)							6.63
Vested (in dollars per share)							30.31
Forfeited (in dollars per share)							11.01
Non-vested, end of period (in dollars per share)					$ 8.76		$ 8.76
Fair value of units vested					$ 0.0	6.0	$ 5.5	7.9
Units withheld for payroll taxes (in shares)							69,052
Aggregate intrinsic value of units vested					0.0	$ 1.6	$ 0.9	$ 3.4
Unrecognized compensation cost related to non-vested restricted incentive units					$ 12.3		$ 12.3
Unrecognized compensation costs, weighted average period for recognition							1 year 6 months
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting							0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting							200.00%

XML

Derivatives - Interest Rate Swaps (Details) - USD ($)	3 Months Ended										9 Months Ended
	Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Sep. 30, 2019		Jun. 30, 2019		Sep. 30, 2020		Sep. 30, 2019		Dec. 31, 2019	Apr. 30, 2019
Derivatives
Derivative, notional amount																$ 850,000,000.0
Derivative, fixed interest rate																2.28%
Income tax (benefit) expense	$ 1,100,000	[1]	$ 500,000		$ (4,000,000.0)		$ (500,000)		$ (3,600,000)		$ (2,400,000)		$ (4,100,000)
(Loss) gain on designated cash flow hedge	3,600,000	[1],[2]	$ 1,500,000	[3]	$ (13,100,000)	[4]	(1,300,000)	[1],[5]	$ (9,900,000)	[6]	(8,000,000.0)	[1]	(11,200,000)	[1]
(Loss) gain on interest rate swaps	4,600,000						(100,000)				9,600,000		(400,000)
Interest expense expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	18,600,000										18,600,000
Fair value of derivative liabilities—current	(33,100,000)										(33,100,000)				$ (14,400,000)
Fair value of derivative liabilities—long-term	(4,500,000)										(4,500,000)				(6,800,000)
Interest rate swaps
Derivatives
Change in fair value of derivatives	4,700,000						$ (1,800,000)				(10,400,000)		$ (15,300,000)
Fair value of derivative liabilities—current	(18,500,000)										(18,500,000)				(5,600,000)
Fair value of derivative liabilities—long-term	(4,500,000)										(4,500,000)				(6,800,000)
Net fair value of commodity swaps	$ (23,000,000.0)										$ (23,000,000.0)				$ (12,400,000)

[1] Includes a tax expense of $1.1 million and a tax benefit of $2.4 million for the three and nine months ended September 30, 2020, respectively, and a tax benefit of $0.5 million and $4.1 million for the three and nine months ended September 30, 2019, respectively.

[2] Includes a tax expense of $1.1 million.

[3] Includes a tax expense of $0.5 million.

[4] Includes a tax benefit of $4.0 million.

[5] Includes a tax benefit of $0.5 million.

[6] Includes a tax benefit of $3.6 million.

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Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivatives
Gain (loss) on derivative activity	$ (5.1)	$ 7.5	$ (8.3)	$ 16.2
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	(2.2)	(0.5)	(8.0)	4.7
Realized gain (loss) on derivatives	(2.9)	8.0	(0.3)	11.5
Gain (loss) on derivative activity	$ (5.1)	$ 7.5	$ (8.3)	$ 16.2

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Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Derivatives
Fair value of derivative assets—current	$ 9.6	$ 12.9
Fair value of derivative assets—long-term	5.4	4.3
Fair value of derivative liabilities—current	(33.1)	(14.4)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	9.6	12.9
Fair value of derivative assets—long-term	5.4	4.3
Fair value of derivative liabilities—current	(14.6)	(8.8)
Net fair value of commodity swaps	$ 0.4	$ 8.4

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Derivatives - Commodities (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) MMBTU gal MMBbls	Dec. 31, 2019 USD ($)
Derivatives
Net Fair Value	$ 0.4	$ 8.4
Commodity
Derivatives
Net Fair Value	0.4
Maximum loss if counterparties fail to perform	15.0
Possible reduction in maximum loss if counterparties fail to perform	$ 9.1
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	161.6
Net Fair Value	$ (8.5)
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	1.9
Net Fair Value	$ 0.0
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	18.1
Net Fair Value	$ (2.3)
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	11.3
Net Fair Value	$ 0.5
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	9.5
Net Fair Value	$ 8.5
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	0.6
Net Fair Value	$ 2.2

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Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Interest rate swaps
Fair Value
Net Fair Value	$ (23.0)	$ (12.4)
Level 2 | Interest rate swaps | Recurring
Fair Value
Net Fair Value	(23.0)	(12.4)
Level 2 | Commodity swaps | Recurring
Fair Value
Net Fair Value	$ 0.4	$ 8.4

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Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Fair Value
Debt issuance costs	$ 26.4	$ 29.8
Carrying Value
Fair Value
Long-term debt	4,650.0	4,764.3
Fair Value
Fair Value
Long-term debt	$ 3,892.8	$ 4,444.2

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Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Segment Reporting
Revenue from contracts with customers	$ 933.6	$ 1,400.5	$ 2,837.8	$ 4,881.0
Cost of sales	(549.5)	(999.5)	(1,702.5)	(3,663.0)
Operating expenses	(94.3)	(119.2)	(283.1)	(351.6)
Gain (loss) on derivative activity	(5.1)	7.5	(8.3)	16.2
Segment profit (loss)	284.7	289.3	843.9	882.6
Depreciation and amortization	(160.3)	(157.3)	(481.3)	(463.1)
Impairments	0.0	0.0	(354.5)	(186.5)
Goodwill	0.0	1,123.7	0.0	1,123.7	$ 184.6
Capital expenditures	43.2	196.5	227.2	619.1
Permian
Segment Reporting
Revenue from contracts with customers	254.7	539.4	831.0	2,024.3
Cost of sales	(185.4)	(474.2)	(637.7)	(1,830.9)
Operating expenses	(22.9)	(28.9)	(71.1)	(85.1)
Gain (loss) on derivative activity	0.0	0.0	0.0	0.0
Segment profit (loss)	46.4	36.3	122.2	108.3
Depreciation and amortization	(31.9)	(31.6)	(92.1)	(89.6)
Impairments			(184.6)	0.0
Goodwill		184.6		184.6
Capital expenditures	28.5	119.7	161.4	268.0
Louisiana
Segment Reporting
Revenue from contracts with customers	541.5	635.0	1,514.7	2,163.6
Cost of sales	(441.4)	(529.6)	(1,213.6)	(1,844.1)
Operating expenses	(31.1)	(38.4)	(90.4)	(111.6)
Gain (loss) on derivative activity	0.0	0.0	0.0	0.0
Segment profit (loss)	69.0	67.0	210.7	207.9
Depreciation and amortization	(36.9)	(37.3)	(109.3)	(116.0)
Impairments			(169.9)	(186.5)
Goodwill		0.0		0.0
Capital expenditures	8.5	21.5	39.3	82.0
Oklahoma
Segment Reporting
Revenue from contracts with customers	228.9	283.2	628.7	902.1
Cost of sales	(101.0)	(148.4)	(255.8)	(492.0)
Operating expenses	(20.1)	(25.7)	(62.4)	(77.2)
Gain (loss) on derivative activity	0.0	0.0	0.0	0.0
Segment profit (loss)	107.8	109.1	310.5	332.9
Depreciation and amortization	(53.0)	(51.1)	(163.7)	(144.8)
Impairments			0.0	0.0
Goodwill		813.4		813.4
Capital expenditures	2.6	48.6	14.1	227.1
North Texas
Segment Reporting
Revenue from contracts with customers	115.0	137.0	342.1	461.1
Cost of sales	(28.2)	(41.4)	(74.1)	(166.1)
Operating expenses	(20.2)	(26.2)	(59.2)	(77.7)
Gain (loss) on derivative activity	0.0	0.0	0.0	0.0
Segment profit (loss)	66.6	69.4	208.8	217.3
Depreciation and amortization	(36.8)	(35.4)	(110.4)	(106.6)
Impairments			0.0	0.0
Goodwill		125.7		125.7
Capital expenditures	3.0	5.0	10.7	36.3
Corporate
Segment Reporting
Revenue from contracts with customers	(206.5)	(194.1)	(478.7)	(670.1)
Cost of sales	206.5	194.1	478.7	670.1
Operating expenses	0.0	0.0	0.0	0.0
Gain (loss) on derivative activity	(5.1)	7.5	(8.3)	16.2
Segment profit (loss)	(5.1)	7.5	(8.3)	16.2
Depreciation and amortization	(1.7)	(1.9)	(5.8)	(6.1)
Impairments			0.0	0.0
Goodwill		0.0		0.0
Capital expenditures	0.6	1.7	1.7	5.7
Product sales
Segment Reporting
Revenue from contracts with customers	696.1	1,137.2	2,121.6	4,118.5
Product sales | Permian
Segment Reporting
Revenue from contracts with customers	129.2	434.0	548.8	1,682.5
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers	500.4	587.6	1,378.5	2,026.6
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	50.5	87.4	143.3	280.7
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers	16.0	28.2	51.0	128.7
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers	179.0	193.1	481.3	657.4
Product sales, Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers	46.5	24.3	94.0	59.4
Product sales, Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers	76.4	92.0	226.6	316.8
Product sales, Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	40.1	54.6	110.0	176.5
Product sales, Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers	16.0	22.2	50.7	104.7
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers	403.6	431.9	1,060.3	1,535.6
Product sales, NGL sales | Permian
Segment Reporting
Revenue from contracts with customers	0.1	0.3	0.2	0.9
Product sales, NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers	402.3	421.0	1,056.9	1,492.9
Product sales, NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	1.2	4.6	2.9	17.8
Product sales, NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers	0.0	6.0	0.3	24.0
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers	113.5	512.2	580.0	1,925.5
Product sales, Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers	82.6	409.4	454.6	1,622.2
Product sales, Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers	21.7	74.6	95.0	216.9
Product sales, Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	9.2	28.2	30.4	86.4
Product sales, Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	95.6	72.0	201.1	256.9
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	3.3	9.6	13.3	18.1
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	85.4	90.2	208.9	320.9
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	22.1	22.1	55.1	75.8
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(206.4)	(193.9)	(478.4)	(671.7)
Product sales, Natural gas sales—related parties
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers		(0.1)		0.3
Product sales, Natural gas sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0.0		0.3
Product sales, Natural gas sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		0.1		(0.6)
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales, NGL sales, related party | Permian
Segment Reporting
Revenue from contracts with customers	95.6	69.3	201.0	242.9
Product sales, NGL sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	3.3	7.9	13.3	16.4
Product sales, NGL sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	85.4	90.2	209.0	320.9
Product sales, NGL sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers	21.4	21.0	52.5	71.7
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(205.7)	(188.4)	(475.8)	(651.9)
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Product sales, Crude oil and condensate sales, related party | Permian
Segment Reporting
Revenue from contracts with customers	0.0	2.8	0.1	13.7
Product sales, Crude oil and condensate sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	0.0	1.7	0.0	1.7
Product sales, Crude oil and condensate sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.0	0.0	(0.1)	0.0
Product sales, Crude oil and condensate sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers	0.7	1.1	2.6	3.8
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(0.7)	(5.6)	(2.6)	(19.2)
Midstream services
Segment Reporting
Revenue from contracts with customers	237.5	263.3	716.2	762.5
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers	29.9	33.4	81.1	84.9
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers	37.8	37.8	122.9	122.2
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers	92.9	105.4	276.2	298.8
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers	76.9	86.7	236.0	256.6
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers	128.7	140.7	380.2	409.6
Midstream services, Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers	17.9	14.7	47.3	36.3
Midstream services, Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers	10.7	12.2	33.9	46.1
Midstream services, Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers	56.7	63.7	165.5	178.2
Midstream services, Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers	43.4	50.1	133.5	149.0
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers	74.0	81.1	220.9	238.1
Midstream services, Processing | Permian
Segment Reporting
Revenue from contracts with customers	8.0	8.3	19.8	23.3
Midstream services, Processing | Louisiana
Segment Reporting
Revenue from contracts with customers	0.3	0.8	1.6	2.5
Midstream services, Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers	32.4	35.7	97.8	105.5
Midstream services, Processing | North Texas
Segment Reporting
Revenue from contracts with customers	33.3	36.3	101.7	106.8
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers	14.2	11.2	52.5	32.9
Midstream services, NGL services | Permian
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers	14.2	11.2	52.4	32.9
Midstream services, NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, NGL services | North Texas
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.1	0.0
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers	19.7	25.8	59.4	72.2
Midstream services, Crude services | Permian
Segment Reporting
Revenue from contracts with customers	3.8	6.4	13.0	16.9
Midstream services, Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers	12.2	13.5	33.8	40.2
Midstream services, Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers	3.7	5.9	12.6	15.1
Midstream services, Crude services | North Texas
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers	0.9	4.5	3.2	9.7
Midstream services, Other services | Permian
Segment Reporting
Revenue from contracts with customers	0.2	4.0	1.0	8.4
Midstream services, Other services | Louisiana
Segment Reporting
Revenue from contracts with customers	0.4	0.1	1.2	0.5
Midstream services, Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.1	0.3	0.0
Midstream services, Other services | North Texas
Segment Reporting
Revenue from contracts with customers	0.2	0.3	0.7	0.8
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	(3.3)
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.2	0.3	1.7
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(0.1)	(0.2)	(0.3)	1.6
Midstream services, NGL services, related party
Segment Reporting
Revenue from contracts with customers				0.0
Midstream services, NGL services, related party | Permian
Segment Reporting
Revenue from contracts with customers				0.0
Midstream services, NGL services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers				(3.3)
Midstream services, NGL services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers				0.0
Midstream services, NGL services, related party | North Texas
Segment Reporting
Revenue from contracts with customers				0.0
Midstream services, NGL services, related party | Corporate
Segment Reporting
Revenue from contracts with customers				3.3
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Crude services, related party | Permian
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Crude services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Crude services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.2	0.3	1.7
Midstream services, Crude services, related party | North Texas
Segment Reporting
Revenue from contracts with customers	0.0	0.0	0.0	0.0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers	$ (0.1)	$ (0.2)	$ (0.3)	$ (1.7)

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Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Segment Reporting [Abstract]
Segment profit	$ 284.7	$ 289.3	$ 843.9	$ 882.6
General and administrative expenses	(25.7)	(38.5)	(79.6)	(122.1)
Gain (loss) on disposition of assets	1.8	3.0	(2.8)	2.9
Depreciation and amortization	(160.3)	(157.3)	(481.3)	(463.1)
Impairments	0.0	0.0	(354.5)	(186.5)
Loss on secured term loan receivable	0.0	0.0	0.0	(52.9)
Operating income (loss)	$ 100.5	$ 96.5	$ (74.3)	$ 60.9

XML

Segment Information - Assets (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Segment Reporting
Total identifiable assets	$ 8,667.2	$ 9,335.8
Permian
Segment Reporting
Total identifiable assets	2,245.3	2,465.7
North Texas
Segment Reporting
Total identifiable assets	1,031.2	1,135.8
Oklahoma
Segment Reporting
Total identifiable assets	2,889.1	3,035.0
Louisiana
Segment Reporting
Total identifiable assets	2,278.9	2,562.0
Corporate
Segment Reporting
Total identifiable assets	$ 222.7	$ 137.3

XML

Other Information (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Other current assets:
Natural gas and NGLs inventory	$ 63.9	$ 43.4
Prepaid expenses and other	17.8	14.4
Other current assets	81.7	57.8
Other current liabilities:
Accrued interest	66.7	37.1
Accrued wages and benefits, including taxes	18.3	31.5
Accrued ad valorem taxes	33.9	28.5
Capital expenditure accruals	12.1	42.4
Retainage liability	11.8	8.7
Short-term lease liability	17.1	21.1
Suspense producer payments	10.3	13.8
Operating expense accruals	10.5	10.8
Other	18.1	12.3
Other current liabilities	$ 198.8	$ 206.2

XML

Subsequent Event (Details) - USD ($)			3 Months Ended		9 Months Ended
	Oct. 22, 2020	Oct. 21, 2020	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Nov. 05, 2020
Subsequent Event [Line Items]
Loss on disposition of property			$ (1,800,000)	$ (3,000,000.0)	$ 2,800,000	$ (2,900,000)
Subsequent Event
Subsequent Event [Line Items]
Proceeds from sale of productive assets	$ 20,000,000
Loss on disposition of property	$ 8,000,000
Repurchase program, amount authorized							$ 100,000,000
Subsequent Event | Line of Credit | Asset-backed Securities
Subsequent Event [Line Items]
Accounts receivable securitization facility, term		3 years
Maximum borrowing capacity		$ 250,000,000
Drawn fee percentage		1.625%
Accounts receivable securitization facility, outstanding amount		$ 225,000,000
Subsequent Event | Line of Credit | Asset-backed Securities | LIBOR | Minimum
Subsequent Event [Line Items]
Variable rate		0.375%

XML

Label	Element	Value
Accounting Standards Update [Extensible List]	us-gaap_AccountingStandardsUpdateExtensibleList	us-gaap:AccountingStandardsUpdate201602Member