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 March 31, ~~2020~~2021

☐ 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

~~Liability Company Interests~~

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

As of April ~~30, 2020,~~29, 2021, the Registrant had ~~489,259,906~~490,055,937 common units outstanding.

Table of Contents

TABLE OF CONTENTS

Table of Contents

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.
Adjusted gross margin						Revenue less cost of sales, exclusive of operating expenses and depreciation and amortization related to our operating segments. Adjusted gross 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.
AR Facility						A three-year committed accounts receivable securitization facility of up to $300 million entered into by EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity and our indirect subsidiary, with PNC Bank, National Association, as administrative agent and lender, and PNC Capital Markets, LLC, as structuring agent.
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.
~~Avenger~~						~~Avenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.~~
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.”
~~ENLK Credit Facility~~						A $1.5 billion unsecured revolving credit facility entered into by ENLK that would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
~~EOGP~~						EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. As of January 31, 2019, EOGP became a wholly-owned subsidiary of the Operating Partnership.
FASB						Financial Accounting Standards Board.
GAAP						Generally accepted accounting principles in the United States of America.
Gal						Gallons.
GCF						Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
General Partner						EnLink Midstream GP, LLC, the general partner of ENLK.
GIP						Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.

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

~~Gross Operating Margin~~						Revenue less cost of sales. Gross Operating Margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information.
ISDAs						International Swaps and Derivatives Association Agreements.

~~Table of Contents~~


~~Legacy ENLK Awards~~						Unit-based awards granted under the GP Plan prior to the Merger. As of the closing of the Merger, Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio from the Merger Agreement as the conversion rate. No additional awards will be granted under the GP Plan.

Managing Member						EnLink Midstream Manager, LLC, the managing member of ENLC.
Merger						On January 25, 2019, NOLA Merger Sub, LLC (previously a wholly-owned subsidiary of ENLC) merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
~~Merger Agreement~~Midland Basin						~~The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, the General Partner, ENLC, the Managing Member, and NOLA Merger Sub related to the Merger.~~A large sedimentary basin in West Texas.
MMbbls						Million barrels.
MMbtu						Million British thermal units.
~~MMcf~~						~~Million cubic feet.~~
MVC						Minimum volume commitment.

Table of Contents


NGL						Natural gas liquid.
NGP						NGP Natural Resources XI, LP.
~~NOLA Merger Sub~~						~~NOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.~~
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.
Permian Basin						A large sedimentary basin that includes the Midland and Delaware Basins.
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						AnA term loan originally in the amount of $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.
~~Thunderbird Plant~~						~~A gas processing plant in Central Oklahoma.~~
~~Tiger Plant~~						~~A gas processing plant that is under construction in the Delaware Basin and is owned by the Delaware Basin JV.~~

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


		March 31, 2020		December 31, 2019			March 31, 2021		December 31, 2020
		(Unaudited)					(Unaudited)
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	258.1	$	77.4	Cash and cash equivalents	$	72.8	$	39.6
Accounts receivable:	Accounts receivable:					Accounts receivable:
Trade, net of allowance for bad debt of $0.6 and $0.5, respectively		34.2		36.2
Trade, net of allowance for bad debt of $0.3 and $0.5, respectively						Trade, net of allowance for bad debt of $0.3 and $0.5, respectively	65.4		80.6
Accrued revenue and other	Accrued revenue and other	337.4		460.1		Accrued revenue and other	481.4		447.5

Fair value of derivative assets	Fair value of derivative assets	75.0		12.9		Fair value of derivative assets	40.2		25.0
Other current assets	Other current assets	19.0		57.8		Other current assets	65.6		58.7
Total current assets	Total current assets	723.7		644.4		Total current assets	725.4		651.4
Property and equipment, net of accumulated depreciation of $3,545.2 and $3,418.6, respectively		6,896.3		7,081.3
Intangible assets, net of accumulated amortization of $576.8 and $545.9, respectively		1,219.0		1,249.9
Goodwill		—		184.6
Property and equipment, net of accumulated depreciation of $3,981.4 and $3,863.0, respectively						Property and equipment, net of accumulated depreciation of $3,981.4 and $3,863.0, respectively	6,551.2		6,652.1
Intangible assets, net of accumulated amortization of $699.7 and $668.8, respectively						Intangible assets, net of accumulated amortization of $699.7 and $668.8, respectively	1,094.5		1,125.4

Investment in unconsolidated affiliates	Investment in unconsolidated affiliates	43.0		43.1		Investment in unconsolidated affiliates	31.7		41.6
Fair value of derivative assets	Fair value of derivative assets	8.2		4.3		Fair value of derivative assets	3.4		4.9
Other assets, net	Other assets, net	164.9		128.2		Other assets, net	110.1		75.5
Total assets	Total assets	$	9,055.1	$	9,335.8	Total assets	$	8,516.3	$	8,550.9
LIABILITIES AND MEMBERS’ EQUITY	LIABILITIES AND MEMBERS’ EQUITY					LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable and drafts payable	Accounts payable and drafts payable	$	51.2	$	70.6	Accounts payable and drafts payable	$	58.7	$	60.5
Accounts payable to related party	Accounts payable to related party	0.5		1.1		Accounts payable to related party	1.2		1.0
Accrued gas, NGLs, condensate, and crude oil purchases	Accrued gas, NGLs, condensate, and crude oil purchases	176.1		354.8		Accrued gas, NGLs, condensate, and crude oil purchases	363.1		290.5
Fair value of derivative liabilities	Fair value of derivative liabilities	77.9		14.4		Fair value of derivative liabilities	59.3		37.1

Current maturities of long-term debt						Current maturities of long-term debt	349.8		349.8
Other current liabilities	Other current liabilities	216.8		206.2		Other current liabilities	165.9		149.1
Total current liabilities	Total current liabilities	522.5		647.1		Total current liabilities	998.0		888.0
Long-term debt	Long-term debt	4,954.8		4,764.3		Long-term debt	4,145.2		4,244.0
Asset retirement obligations	Asset retirement obligations	15.7		15.5		Asset retirement obligations	14.4		14.2
Other long-term liabilities	Other long-term liabilities	87.7		90.8		Other long-term liabilities	85.3		80.6

Deferred tax liability, net						Deferred tax liability, net	111.0		108.6
Fair value of derivative liabilities	Fair value of derivative liabilities	13.4		6.8		Fair value of derivative liabilities	0		2.5

Redeemable non-controlling interest		—		5.2

Members’ equity:	Members’ equity:					Members’ equity:
Members’ equity (489,137,038 and 487,791,612 units issued and outstanding, respectively)		1,764.4		2,135.5
Members’ equity (490,055,402 and 489,381,149 units issued and outstanding, respectively)						Members’ equity (490,055,402 and 489,381,149 units issued and outstanding, respectively)	1,454.2		1,508.8
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(24.1)		(11.0)		Accumulated other comprehensive loss	(11.7)		(15.3)
Non-controlling interest	Non-controlling interest	1,720.7		1,681.6		Non-controlling interest	1,719.9		1,719.5
Total members’ equity	Total members’ equity	3,461.0		3,806.1		Total members’ equity	3,162.4		3,213.0
Commitments and contingencies (Note 15)						Commitments and contingencies (Note 15)	0		0
Total liabilities and members’ equity	Total liabilities and members’ equity	$	9,055.1	$	9,335.8	Total liabilities and members’ equity	$	8,516.3	$	8,550.9

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
		(Unaudited)							(Unaudited)
Revenues:	Revenues:					Revenues:
Product sales	Product sales	$	892.9	$	1,530.9	Product sales	$	1,122.9	$	892.9

Midstream services	Midstream services	244.0		246.5		Midstream services	208.9		244.0

Gain on derivative activity		19.2		1.8
Gain (loss) on derivative activity						Gain (loss) on derivative activity	(83.4)		19.2
Total revenues	Total revenues	1,156.1		1,779.2		Total revenues	1,248.4		1,156.1
Operating costs and expenses:	Operating costs and expenses:					Operating costs and expenses:
Cost of sales		755.3		1,363.4
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)						Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	934.7		755.3
Operating expenses	Operating expenses	100.7		114.5		Operating expenses	56.3		100.7
General and administrative		30.4		51.4
Gain on disposition of assets		(0.6)		—
Depreciation and amortization	Depreciation and amortization	162.8		152.1		Depreciation and amortization	151.0		162.8
Impairments	Impairments	353.0		186.5		Impairments	0		353.0
Gain on disposition of assets						Gain on disposition of assets	0		(0.6)
General and administrative						General and administrative	26.0		30.4

Total operating costs and expenses	Total operating costs and expenses	1,401.6		1,867.9		Total operating costs and expenses	1,168.0		1,401.6
Operating loss		(245.5)		(88.7)
Operating income (loss)						Operating income (loss)	80.4		(245.5)
Other income (expense):	Other income (expense):					Other income (expense):
Interest expense, net of interest income	Interest expense, net of interest income	(55.6)		(49.6)		Interest expense, net of interest income	(60.0)		(55.6)
Gain on extinguishment of debt	Gain on extinguishment of debt	5.3		—		Gain on extinguishment of debt	0		5.3
Income from unconsolidated affiliates		1.7		5.3

Income (loss) from unconsolidated affiliates						Income (loss) from unconsolidated affiliates	(6.3)		1.7
Other expense						Other expense	(0.1)		0
Total other expense	Total other expense	(48.6)		(44.3)		Total other expense	(66.4)		(48.6)
Loss before non-controlling interest and income taxes		(294.1)		(133.0)
Income (loss) before non-controlling interest and income taxes						Income (loss) before non-controlling interest and income taxes	14.0		(294.1)
Income tax benefit (expense)	Income tax benefit (expense)	33.7		(1.8)		Income tax benefit (expense)	(1.4)		33.7
Net loss		(260.4)		(134.8)
Net income (loss)						Net income (loss)	12.6		(260.4)
Net income attributable to non-controlling interest	Net income attributable to non-controlling interest	26.4		41.5		Net income attributable to non-controlling interest	25.3		26.4
Net loss attributable to ENLC	Net loss attributable to ENLC	$	(286.8)	$	(176.3)	Net loss attributable to ENLC	$	(12.7)	$	(286.8)
Net loss attributable to ENLC per unit:	Net loss attributable to ENLC per unit:					Net loss attributable to ENLC per unit:
Basic common unit	Basic common unit	$	(0.59)	$	(0.45)	Basic common unit	$	(0.03)	$	(0.59)
Diluted common unit	Diluted common unit	$	(0.59)	$	(0.45)	Diluted common unit	$	(0.03)	$	(0.59)

____________________________

(1)

Includes related party cost of sales of $3.2 million and $2.9 million for the three months ended March 31, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $149.0 million and $160.8 million for the three months ended March 31, 2021 and 2020, respectively.

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive ~~Loss~~Income (Loss)

(In millions)

Three Months Ended
March 31,
2020 2019
(Unaudited)
Net loss $ (260.4) $ (134.8)
Loss on designated cash flow hedge (1) (13.1) —
Comprehensive loss (273.5) (134.8)
Comprehensive income attributable to non-controlling interest 26.4 41.5
Comprehensive loss attributable to ENLC $ (299.9) $ (176.3)


	Three Months Ended March 31,
	2021		2020
	(Unaudited)
Net income (loss)	$	12.6	$	(260.4)
Gain (loss) on designated cash flow hedge (1)	3.6		(13.1)
Comprehensive income (loss)	16.2		(273.5)
Comprehensive income attributable to non-controlling interest	25.3		26.4
Comprehensive loss attributable to ENLC	$	(9.1)	$	(299.9)

____________________________

(1)Includes a tax expense of $1.1 million and a tax benefit of $4.0 million for the three months ended March 31, ~~2020.~~

2021 and 2020, respectively.

See accompanying notes to consolidated financial statements.

Table of Contents

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)	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-controlling interest (Temporary Equity)
		$		Units	$		$		$		$			$		Units	$		$		$		$
		(Unaudited)																					(Unaudited)
Balance, December 31, 2019		$	2,135.5	487.8	$	(11.0)	$	1,681.6	$	3,806.1	$	5.2
Balance, December 31, 2020													Balance, December 31, 2020	$	1,508.8	489.4	$	(15.3)	$	1,719.5	$	3,213.0	$	0
Conversion of restricted units for common units, net of units withheld for taxes	Conversion of restricted units for common units, net of units withheld for taxes	(4.0)		1.3	—		—		(4.0)		—		Conversion of restricted units for common units, net of units withheld for taxes	(1.2)		0.7	—		—		(1.2)		—
Unit-based compensation	Unit-based compensation	12.3		—	—		—		12.3		—		Unit-based compensation	6.5		—	—		—		6.5		—
Contributions from non-controlling interests	Contributions from non-controlling interests	—		—	—		37.1		37.1		—		Contributions from non-controlling interests	—		—	—		0.9		0.9		—
Distributions	Distributions	(93.3)		—	—		(24.4)		(117.7)		(0.3)		Distributions	(47.1)		—	—		(25.8)		(72.9)		(0.2)
Loss on designated cash flow hedge (1)		—		—	(13.1)		—		(13.1)		—
Redemption of non-controlling interest		—		—	—		—		—		(4.0)
Gain on designated cash flow hedge (1)													Gain on designated cash flow hedge (1)	—		—	3.6		—		3.6		—
Fair value adjustment related to redeemable non-controlling interest	Fair value adjustment related to redeemable non-controlling interest	0.7		—	—		—		0.7		(0.9)		Fair value adjustment related to redeemable non-controlling interest	(0.1)		—	—		—		(0.1)		0.2

Net income (loss)	Net income (loss)	(286.8)		—	—		26.4		(260.4)		—		Net income (loss)	(12.7)		—	—		25.3		12.6		—
Balance, March 31, 2020		$	1,764.4	489.1	$	(24.1)	$	1,720.7	$	3,461.0	$	—
Balance, March 31, 2021													Balance, March 31, 2021	$	1,454.2	490.1	$	(11.7)	$	1,719.9	$	3,162.4	$	0

____________________________

(1)Includes a tax ~~benefit~~expense of ~~$4.0~~$1.1 million.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity (Continued)

(In millions)


		Common Units					Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total				Redeemable Non-Controlling Interest (Temporary Equity)	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-Controlling Interest (Temporary Equity)
		$		Units	$		$		$		$			$		Units	$		$		$		$
		(Unaudited)																					(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
Balance, December 31, 2019													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	Conversion of restricted units for common units, net of units withheld for taxes	(5.6)		1.0	—		(2.8)		(8.4)		—		Conversion of restricted units for common units, net of units withheld for taxes	(4.0)		1.3	—		0		(4.0)		—
Unit-based compensation	Unit-based compensation	12.2		—	—		1.4		13.6		—		Unit-based compensation	12.3		—	—		0		12.3		—
Contributions from non-controlling interests	Contributions from non-controlling interests	—		—	—		15.7		15.7		—		Contributions from non-controlling interests	—		—	—		37.1		37.1		—
Distributions	Distributions	(51.0)		—	—		(127.6)		(178.6)		—		Distributions	(93.3)		—	—		(24.4)		(117.7)		(0.3)

Loss on designated cash flow hedge (1)													Loss on designated cash flow hedge (1)	—		—	(13.1)		—		(13.1)		—
Fair value adjustment related to redeemable non-controlling interest	Fair value adjustment related to redeemable non-controlling interest	2.5		—	—		—		2.5		(2.1)		Fair value adjustment related to redeemable non-controlling interest	0.7		—	—		—		0.7		(0.9)
Redemption of non-controlling interest													Redemption of non-controlling interest	—		—	—		—		—		(4.0)
Net income (loss)	Net income (loss)	(176.3)		—	—		41.5		(134.8)		—		Net income (loss)	(286.8)		—	—		26.4		(260.4)		0
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
Balance, March 31, 2020													Balance, March 31, 2020	$	1,764.4	489.1	$	(24.1)	$	1,720.7	$	3,461.0	$	0

____________________________

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

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
		(Unaudited)							(Unaudited)
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net loss		$	(260.4)	$	(134.8)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net income (loss)						Net income (loss)	$	12.6	$	(260.4)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:						Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	Impairments	353.0		186.5		Impairments	0		353.0
Depreciation and amortization	Depreciation and amortization	162.8		152.1		Depreciation and amortization	151.0		162.8
Utility credits						Utility credits	(40.4)		0
Deferred income tax (benefit) expense	Deferred income tax (benefit) expense	(34.0)		0.8		Deferred income tax (benefit) expense	1.3		(34.0)

Non-cash unit-based compensation	Non-cash unit-based compensation	8.8		11.1		Non-cash unit-based compensation	6.5		8.8
Gain on derivatives recognized in net loss		(19.2)		(1.8)
Cash settlements on derivatives		1.2		4.6
Non-cash (gain) loss on derivatives recognized in net income (loss)						Non-cash (gain) loss on derivatives recognized in net income (loss)	7.8		(18.0)
Gain on extinguishment of debt	Gain on extinguishment of debt	(5.3)		—		Gain on extinguishment of debt	0		(5.3)
Amortization of debt issue costs, net discount (premium) of notes	Amortization of debt issue costs, net discount (premium) of notes	1.0		1.8		Amortization of debt issue costs, net discount (premium) of notes	1.2		1.0

Distribution of earnings from unconsolidated affiliates	Distribution of earnings from unconsolidated affiliates	1.6		2.2		Distribution of earnings from unconsolidated affiliates	0		1.6
Income from unconsolidated affiliates		(1.7)		(5.3)
(Income) loss from unconsolidated affiliates						(Income) loss from unconsolidated affiliates	6.3		(1.7)

Other operating activities	Other operating activities	(1.2)		(0.4)		Other operating activities	1.4		(1.2)
Changes in assets and liabilities:	Changes in assets and liabilities:					Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	Accounts receivable, accrued revenue, and other	124.8		93.8		Accounts receivable, accrued revenue, and other	(18.7)		124.8
Natural gas and NGLs inventory, prepaid expenses, and other	Natural gas and NGLs inventory, prepaid expenses, and other	44.5		3.6		Natural gas and NGLs inventory, prepaid expenses, and other	1.2		44.5
Accounts payable, accrued product purchases, and other accrued liabilities	Accounts payable, accrued product purchases, and other accrued liabilities	(193.9)		(50.2)		Accounts payable, accrued product purchases, and other accrued liabilities	95.6		(193.9)
Net cash provided by operating activities	Net cash provided by operating activities	182.0		264.0		Net cash provided by operating activities	225.8		182.0
Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Additions to property and equipment	Additions to property and equipment	(112.0)		(241.5)		Additions to property and equipment	(23.5)		(112.0)

Distribution from unconsolidated affiliates in excess of earnings						Distribution from unconsolidated affiliates in excess of earnings	3.6		0.2
Other investing activities	Other investing activities	(3.5)		0.5		Other investing activities	0.7		(3.7)
Net cash used in investing activities	Net cash used in investing activities	(115.5)		(241.0)		Net cash used in investing activities	(19.2)		(115.5)
Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Proceeds from borrowings	Proceeds from borrowings	440.0		630.0		Proceeds from borrowings	200.0		440.0
Payments on borrowings	Payments on borrowings	(241.0)		(581.4)		Payments on borrowings	(300.0)		(241.0)
Debt financing costs		—		(5.6)

Conversion of restricted units, net of units withheld for taxes	Conversion of restricted units, net of units withheld for taxes	(4.0)		(8.4)		Conversion of restricted units, net of units withheld for taxes	(1.2)		(4.0)
Distribution to members	Distribution to members	(93.3)		(51.0)		Distribution to members	(47.1)		(93.3)
Distributions to non-controlling interests	Distributions to non-controlling interests	(24.7)		(127.6)		Distributions to non-controlling interests	(26.0)		(24.7)
Contributions by non-controlling interests	Contributions by non-controlling interests	37.1		15.7		Contributions by non-controlling interests	0.9		37.1
Other financing activities	Other financing activities	0.1		5.6		Other financing activities	0		0.1
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	114.2		(122.7)		Net cash provided by (used in) financing activities	(173.4)		114.2
Net increase (decrease) in cash and cash equivalents		180.7		(99.7)
Net increase in cash and cash equivalents						Net increase in cash and cash equivalents	33.2		180.7
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period	77.4		100.4		Cash and cash equivalents, beginning of period	39.6		77.4
Cash and cash equivalents, end of period	Cash and cash equivalents, end of period	$	258.1	$	0.7	Cash and cash equivalents, end of period	$	72.8	$	258.1

Supplemental disclosures of cash flow information:	Supplemental disclosures of cash flow information:					Supplemental disclosures of cash flow information:
Cash paid for interest	Cash paid for interest	$	22.3	$	23.8	Cash paid for interest	$	17.2	$	22.3

Non-cash investing activities:	Non-cash investing activities:					Non-cash investing activities:
Non-cash accrual of property and equipment	Non-cash accrual of property and equipment	$	2.8	$	9.5	Non-cash accrual of property and equipment	$	(2.7)	$	2.8
Right-of-use assets obtained in exchange for operating lease liabilities						Right-of-use assets obtained in exchange for operating lease liabilities	$	10.2	$	4.8
Non-cash financing activities:	Non-cash financing activities:					Non-cash financing activities:
Redemption of non-controlling interest	Redemption of non-controlling interest	$	(4.0)	$	—	Redemption of non-controlling interest	$	0	$	(4.0)

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

March 31, ~~2020~~2021

(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.~~subsidiaries, including the Operating Partnership.

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~~ENLK’s common units and also owns all 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 membership interests of the 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 midstream energy asset network includes approximately 11,900 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, 7 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. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

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

c.COVID-19 Update

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. There is considerable uncertainty regarding how long the COVID-19 pandemic will persist and affect economic conditions and the extent and duration of changes in consumer behavior.

(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.~~2020. 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 ~~loss.~~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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 months ended March 31, ~~2020,~~2021, we had contractual commitments of ~~$41.8~~$13.5 million under our MVC contracts and recorded ~~$11.8~~$0.3 million of revenue due to volume shortfalls.


MVC and Firm Transportation Commitments (in millions) (1)	MVC and Firm Transportation Commitments (in millions) (1)			MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)		$	199.5
2021		116.7
2021 (remaining)				2021 (remaining)	$	106.3
2022	2022	103.3		2022	127.5
2023	2023	94.8		2023	116.5
2024	2024	81.3		2024	104.4
2025				2025	62.0
Thereafter	Thereafter	158.2		Thereafter	342.1
Total	Total	$	753.8	Total	$	858.8

____________________________

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

c.~~Property and Equipment~~

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

For the three months ended March 31, 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. Additionally, we recorded a $0.4 million impairment related to certain cancelled projects.

d.~~Redeemable Non-Controlling Interest~~

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

During the first quarter of 2020, a non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated liability of $4.0 million related to the redemption of the non-controlling interest on the consolidated balance sheet as of March 31, 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder.

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

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 months ended March 31, 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.

(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.

~~The following table represents our change in carrying value of goodwill by segment (in millions):~~

Permian North Texas Oklahoma Louisiana Corporate Totals
Three Months Ended March 31, 2020
Balance, beginning of period $ 184.6 $ — $ — $ — $ — $ 184.6
Impairment (184.6) — — — — (184.6)
Balance, end of period $ — $ — $ — $ — $ — $ —

~~Goodwill Impairment Analysis for the three months ended March 31, 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 three months ended March 31, 2020.

~~Goodwill Impairment Analysis for the three months ended March 31, 2019~~

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

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~Intangible Assets~~

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

Gross Carrying Amount Accumulated Amortization Net Carrying Amount
Three Months Ended March 31, 2020
Customer relationships, beginning of period $ 1,795.8 $ (545.9) $ 1,249.9
Amortization expense — (30.9) (30.9)
Customer relationships, end of period $ 1,795.8 $ (576.8) $ 1,219.0

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 510 to 20 years.

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


	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Three Months Ended March 31, 2021
Customer relationships, beginning of period	$	1,794.2	$	(668.8)	$	1,125.4
Amortization expense	—		(30.9)		(30.9)

Customer relationships, end of period	$	1,794.2	$	(699.7)	$	1,094.5

The weighted average amortization period for intangible assets is 15.0 years. Amortization expense was $30.9 million for each of the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, respectively.

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


2020 (remaining)		$	92.8
2021		123.7
2021 (remaining)				2021 (remaining)	$	92.5
2022	2022	123.7		2022	123.4
2023	2023	123.6		2023	123.4
2024	2024	123.4		2024	123.4
2025				2025	106.1
Thereafter	Thereafter	631.8		Thereafter	525.7

Total	Total	$	1,219.0	Total	$	1,094.5

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(4) Related Party Transactions

Transactions with Cedar Cove JV. For the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, we recorded cost of sales of ~~$2.9~~$3.2 million and ~~$8.1~~$2.9 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at ~~its~~our Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of ~~$0.5~~$1.2 million and ~~$1.1~~$1.0 million at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively.

Transactions with GIP. For the three months ended March 31, 2021, we recorded general and administrative expenses of $0.1 million related to personnel secondment services provided by GIP. We did 0t record any expenses related to transactions with GIP for the three months ended March 31, 2020.

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 specified in the accompanying consolidated financial statements.

(5) ~~Leases~~

~~Lease balances are recorded on the consolidated balance sheets as follows (in millions):~~

March 31, 2020 December 31, 2019
Operating leases:
Other assets, net $ 74.5 $ 80.4
Other current liabilities $ 17.6 $ 21.1
Other long-term liabilities $ 78.8 $ 81.9
Other lease information
Weighted-average remaining lease term—Operating leases 11.0 years 10.6 years
Weighted-average discount rate—Operating leases 5.2 % 5.1 %

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions.

Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions):

Three Months Ended
March 31,
2020 2019
Finance lease expense:
Amortization of right-of-use asset $ — $ 0.7
Operating lease expense:
Long-term operating lease expense 6.4 6.3
Short-term lease expense 5.5 6.9
Variable lease expense 2.8 1.6
Total lease expense $ 14.7 $ 15.5

~~Other information about our leases is presented below (in millions):~~

Three Months Ended
March 31,
2020 2019
Supplemental cash flow information:
Cash payments for finance leases included in cash flows from financing activities $ — $ 0.4
Cash payments for operating leases included in cash flows from operating activities $ 7.2 $ 7.0
Right-of-use assets obtained in exchange for operating lease liabilities $ 4.8 $ 80.6

~~The following table summarizes the maturity of our lease liability as of March 31, 2020 (in millions):~~

Total 2020 (remaining) 2021 2022 2023 2024 Thereafter
Undiscounted operating lease liability $ 133.9 $ 16.3 $ 17.0 $ 12.2 $ 10.2 $ 9.5 $ 68.7
Reduction due to present value (37.5) (3.5) (4.0) (3.6) (3.2) (2.8) (20.4)
Operating lease liability $ 96.4 $ 12.8 $ 13.0 $ 8.6 $ 7.0 $ 6.7 $ 48.3

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~(6)~~ Long-Term Debt

As of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, long-term debt consisted of the following (in millions):


		March 31, 2020										December 31, 2019											March 31, 2021				December 31, 2020
		Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt			Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Consolidated Credit Facility due 2024 (1)		$	550.0	$	—	$	550.0	$	350.0	$	—	$	350.0
Term Loan due 2021 (2)		850.0		—		850.0		850.0		—		850.0
Term Loan due 2021 (1)														Term Loan due 2021 (1)	$	350.0	$	0	$	350.0	$	350.0	$	0	$	350.0
AR Facility due 2023 (2)														AR Facility due 2023 (2)	150.0		0		150.0		250.0		0		250.0
Consolidated Credit Facility due 2024														Consolidated Credit Facility due 2024	0		0		0		0		0		0
ENLK’s 4.40% Senior unsecured notes due 2024	ENLK’s 4.40% Senior unsecured notes due 2024	545.0		1.4		546.4		550.0		1.5		551.5		ENLK’s 4.40% Senior unsecured notes due 2024	521.8		1.0		522.8		521.8		1.1		522.9
ENLK’s 4.15% Senior unsecured notes due 2025	ENLK’s 4.15% Senior unsecured notes due 2025	747.5		(0.7)		746.8		750.0		(0.7)		749.3		ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.5)		720.3		720.8		(0.6)		720.2
ENLK’s 4.85% Senior unsecured notes due 2026	ENLK’s 4.85% Senior unsecured notes due 2026	497.0		(0.4)		496.6		500.0		(0.5)		499.5		ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.4)		490.6		491.0		(0.4)		490.6
ENLC's 5.625% Senior unsecured notes due 2028														ENLC's 5.625% Senior unsecured notes due 2028	500.0		0		500.0		500.0		0		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	ENLC’s 5.375% Senior unsecured notes due 2029	500.0		—		500.0		500.0		—		500.0		ENLC’s 5.375% Senior unsecured notes due 2029	498.7		0		498.7		498.7		0		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8		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	ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.9)		444.1		450.0		(5.9)		444.1		ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.6)		444.4		450.0		(5.7)		444.3
ENLK’s 5.45% Senior unsecured notes due 2047	ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9		ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term, including current maturities of long-term debt		$	4,989.5	$	(5.9)	4,983.6		$	4,800.0	$	(5.9)	4,794.1
Debt classified as long-term														Debt classified as long-term	$	4,532.3	$	(5.8)	4,526.5		$	4,632.3	$	(5.9)	4,626.4
Debt issuance cost (3)	Debt issuance cost (3)					(28.8)						(29.8)		Debt issuance cost (3)					(31.5)						(32.6)
Less: Current maturities of long-term debt (1)														Less: Current maturities of long-term debt (1)					(349.8)						(349.8)
Long-term debt, net of unamortized issuance cost	Long-term debt, net of unamortized issuance cost					$	4,954.8					$	4,764.3	Long-term debt, net of unamortized issuance cost					$	4,145.2					$	4,244.0

____________________________

(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was ~~2.4%~~1.6% and ~~3.3%~~1.7% at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. The Term Loan will mature on December 10, 2021. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of March 31, 2021 and December 31, 2020, respectively.

(2)Bears interest based on ~~Prime~~LIMR and/or LIBOR plus an applicable margin. The effective interest rate was ~~2.2%~~1.4% and ~~3.2%~~2.0% at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively.

(3)Net of amortization of ~~$11.9~~$15.3 million and ~~$10.9~~$14.1 million at March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, 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 ($550.0 million as of March 31, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($18.8 million as of March 31, 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

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

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 March 31, 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 March 31, 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 March 31, 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 three months ended March 31, 2020, ENLK made aggregate payments of $5.2 million to repurchase $10.5 million of the 2024, 2025, and 2026 Notes in open market transactions, which resulted in a $5.3 million gain on extinguishment of debt.

~~(7) Income Taxes~~

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

Three Months Ended
March 31,
2020 2019
Current income tax expense $ (0.3) $ (1.0)
Deferred income tax benefit (expense) 34.0 (0.8)
Income tax benefit (expense) $ 33.7 $ (1.8)

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

ENLC. The outstanding balance of the Term Loan was $350.0 million as of March 31, 2021. The obligations under the Term Loan are unsecured.

At March 31, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the Term Loan until the Term Loan matures on December 10, 2021.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility to borrow up to $250.0 million. In connection with the AR Facility, certain subsidiaries of ENLC have sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. The SPV’s assets are not available to satisfy the obligations of ENLC or any of its affiliates.

On February 26, 2021, the SPV entered into an amendment to the AR Facility that, among other things: (i) increased the AR Facility limit and lender commitments by $50.0 million to $300.0 million, (ii) reduced the Adjusted LIBOR and LMIR (each as defined in the AR Facility) minimum floor to 0, rather than the previous 0.375%, and (iii) reduced the currently effective drawn fee to 1.25% rather than the previous 1.625%.

Since our investment in the SPV is not sufficient to finance its activities without additional support from us, the SPV is a variable interest entity. We are the primary beneficiary of the SPV because we have the power to direct the activities that most significantly affect its economic performance and we are obligated to absorb its losses or receive its benefits from operations. Since we are the primary beneficiary of the SPV, we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $505.9 million and long-term debt of $150.0 million as of March 31, 2021.

The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations. As of March 31, 2021, the AR Facility had a borrowing base of $262.1 million. Borrowings under the AR Facility bear interest (based on LIBOR or LMIR (as defined in the AR Facility)) plus a drawn fee in the amount of 1.25% at March 31, 2021. The drawn fee varies based on ENLC’s credit rating, and the SPV also pays a fee on the undrawn committed amount of the AR Facility. Interest and fees payable by the SPV under the AR Facility are due monthly.

The AR Facility 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 under the AR Facility must be 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 AR Facility become due and payable.

The AR Facility includes covenants, indemnification provisions, and events of default, including those providing for termination of the AR Facility and the acceleration of amounts owed by the SPV under the AR Facility if, among other things, a borrowing base deficiency exists, there is an event of default under the Consolidated Credit Facility, the Term Loan or certain other indebtedness, certain events negatively affecting the overall credit quality of the receivables held as collateral occur, a change of control occurs, or if the consolidated leverage ratio of ENLC exceeds limits identical to those in the Consolidated Credit Facility and the Term Loan.

At March 31, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months.

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’s obligations under the Consolidated Credit Facility are accelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of the outstanding letters of credit under the Consolidated Credit Facility. There were 0 outstanding borrowings under the Consolidated Credit Facility and $27.5 million outstanding letters of credit as of March 31, 2021.

At March 31, 2021, 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.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(6) Income Taxes

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


	Three Months Ended March 31,
	2021		2020
Current income tax expense	$	(0.1)	$	(0.3)
Deferred income tax benefit (expense)	(1.3)		34.0
Income tax benefit (expense)	$	(1.4)	$	33.7

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


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
Expected income tax benefit based on federal statutory rate	Expected income tax benefit based on federal statutory rate	$	67.3	$	36.7	Expected income tax benefit based on federal statutory rate	$	2.4	$	67.3
State income tax benefit, net of federal benefit	State income tax benefit, net of federal benefit	8.0		4.4		State income tax benefit, net of federal benefit	0.2		8.0

Unit-based compensation (1)						Unit-based compensation (1)	(2.5)		2.4
Non-deductible expense related to goodwill impairment	Non-deductible expense related to goodwill impairment	(43.4)		(43.8)		Non-deductible expense related to goodwill impairment	0		(43.4)
Change in valuation allowance						Change in valuation allowance	(1.2)		0
Other	Other	1.8		0.9		Other	(0.3)		(0.6)
Income tax benefit (expense)	Income tax benefit (expense)	$	33.7	$	(1.8)	Income tax benefit (expense)	$	(1.4)	$	33.7

____________________________

(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,~~liabilities, net of deferred tax ~~liabilities,~~assets, are included in ~~“Other assets,~~“Deferred tax liability, net” in the consolidated balance sheets. As of March 31, ~~2020,~~2021, we had ~~$70.1~~$111.0 million of deferred tax liabilities, net of $404.5 million of deferred tax assets, ~~net~~which included a $154.5 million valuation allowance. As of ~~$354.8~~December 31, 2020, we had $108.6 million of deferred tax ~~liabilities. As~~liabilities, net of ~~December 31, 2019, we had $32.2~~$396.0 million of deferred tax assets, ~~net of $354.0~~which included a $153.3 million ~~of deferred tax liabilities.~~

~~(8) Certain Provisions of the ENLK Partnership Agreement~~

a.~~ENLK Series B Preferred Units~~valuation allowance.

A ~~summary~~valuation allowance is established to reduce deferred tax assets if all, or some portion, of ~~the distribution activity relating~~such assets will more than likely not be realized. We established a valuation allowance of $153.3 million as of December 31, 2020, primarily related to ~~the Series B Preferred Units during~~federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. For the three months ended March 31, ~~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
2019
Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019
First Quarter of 2019 147,887 $ 16.7 May 14, 2019

b.~~ENLK Series C Preferred Units~~

~~There was no distribution activity relating to the Series C Preferred Units during the three months ended~~2021, we recorded a $1.2 million valuation allowance adjustment. As of March 31, ~~2020 and 2019.~~

c.~~ENLK Common Unit Distributions~~

~~On February 13, 2019, ENLK paid $0.39 per ENLK common unit related to~~2021, management believes it is more likely than not that the ~~fourth quarter~~Company will realize the benefits of ~~2018.~~the deferred tax assets, net of valuation allowance.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(9)~~(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of March 31, 2021 and December 31, 2020, there were 60,348,278 and 60,197,784 Series B Preferred Units issued and outstanding, respectively.

A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2021 and 2020 is provided below:


Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2021
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021



2020
Fourth Quarter of 2019	148,999	$	16.8	February 13, 2020
First Quarter of 2020	149,371	$	16.8	May 13, 2020

b.Series C Preferred Units

As of March 31, 2021 and December 31, 2020, there were 400,000 Series C Preferred Units issued and outstanding, respectively. There was no distribution activity related to the Series C Preferred Units during the three months ended March 31, 2021 and 2020.

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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 March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
Distributed earnings allocated to:	Distributed earnings allocated to:					Distributed earnings allocated to:
Common units (1)	Common units (1)	$	45.8	$	109.4	Common units (1)	$	45.9	$	45.8
Unvested restricted units (1)	Unvested restricted units (1)	0.8		1.2		Unvested restricted units (1)	1.1		0.8
Total distributed earnings	Total distributed earnings	$	46.6	$	110.6	Total distributed earnings	$	47.0	$	46.6
Undistributed loss allocated to:	Undistributed loss allocated to:					Undistributed loss allocated to:
Common units	Common units	$	(327.4)	$	(283.8)	Common units	$	(58.3)	$	(327.4)
Unvested restricted units	Unvested restricted units	(6.0)		(3.1)		Unvested restricted units	(1.4)		(6.0)
Total undistributed loss	Total undistributed loss	$	(333.4)	$	(286.9)	Total undistributed loss	$	(59.7)	$	(333.4)
Net loss allocated to:	Net loss allocated to:					Net loss allocated to:
Common units	Common units	$	(281.6)	$	(174.4)	Common units	$	(12.4)	$	(281.6)
Unvested restricted units	Unvested restricted units	(5.2)		(1.9)		Unvested restricted units	(0.3)		(5.2)
Total net loss	Total net loss	$	(286.8)	$	(176.3)	Total net loss	$	(12.7)	$	(286.8)
Basic and diluted net loss per unit:
Basic and diluted total net loss per unit:						Basic and diluted total net loss per unit:
Basic	Basic	$	(0.59)	$	(0.45)	Basic	$	(0.03)	$	(0.59)
Diluted	Diluted	$	(0.59)	$	(0.45)	Diluted	$	(0.03)	$	(0.59)

____________________________

(1)~~For~~Represents distribution activity consistent with the ~~three months ended March 31, 2020 and 2019, distributed earnings represent a declared~~ distribution ~~of $0.09375 per unit payable on May 13, 2020 and a distribution of $0.279 per unit paid on May 14, 2019, respectively.~~activity in “Distributions” below.

~~The following are the unit amounts used to compute the basic~~There were 490.0 million and ~~diluted earnings per unit for the periods presented (in millions):~~

Three Months Ended
March 31,
2020 2019
Basic and diluted weighted average units outstanding:
Weighted average common units outstanding (1) 488.7 392.0

~~____________________________~~

~~(1)All~~488.7 million weighted average common ~~unit equivalents were antidilutive~~units outstanding for the three months ended March 31, 2021 and 2020, ~~and 2019 since~~respectively. All common unit equivalents were antidilutive because a net loss existed for those periods.

~~Table~~All outstanding units were included in the computation of ~~Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented.

b.Distributions

A summary of our distribution activity ~~relating~~related to the ENLC common units for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, respectively, is provided below:

Declaration period

Distribution/unit

Date paid/payable

~~2020~~2021

Fourth ~~Quarter of 2019~~

~~0.1875~~

~~February 13, 2020~~

~~First~~ Quarter of 2020

0.09375

February 12, 2021

First Quarter of 2021

0.09375

May ~~13, 2020~~14, 2021

~~2019~~2020

Fourth Quarter of ~~2018~~2019

~~0.275~~0.1875

February ~~14, 2019~~13, 2020

First Quarter of ~~2019~~2020

~~0.279~~0.09375

May ~~14, 2019~~13, 2020

~~(10)~~

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(9) Investment in Unconsolidated Affiliates

As of March 31, ~~2020,~~2021, 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 March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
GCF	GCF					GCF

Distributions	Distributions	$	1.6	$	2.2	Distributions	$	3.5	$	1.6
Equity in income		$	1.8	$	5.7
Equity in income (loss)						Equity in income (loss)	$	(5.7)	$	1.8

Cedar Cove JV	Cedar Cove JV					Cedar Cove JV

Distributions	Distributions	$	0.2	$	0.3	Distributions	$	0.1	$	0.2
Equity in loss	Equity in loss	$	(0.1)	$	(0.4)	Equity in loss	$	(0.6)	$	(0.1)

Total	Total					Total

Distributions	Distributions	$	1.8	$	2.5	Distributions	$	3.6	$	1.8
Equity in income		$	1.7	$	5.3
Equity in income (loss)						Equity in income (loss)	$	(6.3)	$	1.7

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, ~~2020~~2021 and December 31, ~~2019~~2020 (in millions):


		March 31, 2020		December 31, 2019			March 31, 2021		December 31, 2020
GCF	GCF	$	39.4	$	39.2	GCF	$	31.4	$	40.6
Cedar Cove JV	Cedar Cove JV	3.6		3.9		Cedar Cove JV	0.3		1.0
Total investment in unconsolidated affiliates	Total investment in unconsolidated affiliates	$	43.0	$	43.1	Total investment in unconsolidated affiliates	$	31.7	$	41.6

~~(11)~~(10) Employee Incentive Plans

a.Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718,Compensation—Stock Compensation, 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 is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.~~

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


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
Cost of unit-based compensation charged to operating expense	Cost of unit-based compensation charged to operating expense	$	2.2	$	0.3	Cost of unit-based compensation charged to operating expense	$	1.7	$	2.2
Cost of unit-based compensation charged to general and administrative expense	Cost of unit-based compensation charged to general and administrative expense	6.6		10.8		Cost of unit-based compensation charged to general and administrative expense	4.8		6.6
Total unit-based compensation expense	Total unit-based compensation expense	$	8.8	$	11.1	Total unit-based compensation expense	$	6.5	$	8.8
Non-controlling interest in unit-based compensation		$	—	$	0.5
Amount of related income tax benefit recognized in net loss		$	2.1	$	2.5
Amount of related income tax benefit recognized in net income (loss) (1)						Amount of related income tax benefit recognized in net income (loss) (1)	$	1.5	$	2.1

____________________________

(1)For the three months ended March 31, 2021, the amount of related income tax benefit recognized in net income excluded $2.5 million of income tax expense related to book-to-tax differences recorded upon vesting of restricted units. For the three months ended March 31, 2020, the amount of related income tax benefit recognized in net loss excluded $2.4 million of income tax benefit 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 three months ended March 31, ~~2020~~2021 is provided below:


		Three Months Ended March 31, 2020							Three Months Ended March 31, 2021
ENLC Restricted Incentive Units:	ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value		ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	Non-vested, beginning of period	4,063,605		$	13.85	Non-vested, beginning of period	5,350,086		$	8.45
Granted (1)	Granted (1)	4,554,493		5.66		Granted (1)	3,622,698		3.72
Vested (1)(2)	Vested (1)(2)	(1,978,817)		9.56		Vested (1)(2)	(813,686)		12.52
Forfeited	Forfeited	(53,105)		11.34		Forfeited	(116,444)		6.62
Non-vested, end of period	Non-vested, end of period	6,586,176		$	9.50	Non-vested, end of period	8,042,654		$	5.93
Aggregate intrinsic value, end of period (in millions)	Aggregate intrinsic value, end of period (in millions)	$	7.2			Aggregate intrinsic value, end of period (in millions)	$	34.5

____________________________

(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 ~~732,473~~240,085 units withheld for payroll taxes paid on behalf of employees.


		Three Months Ended March 31,							Three Months Ended March 31,
ENLC Restricted Incentive Units:	ENLC Restricted Incentive Units:	2020		2019		ENLC Restricted Incentive Units:	2021		2020
Aggregate intrinsic value of units vested	Aggregate intrinsic value of units vested	$	10.1	$	12.4	Aggregate intrinsic value of units vested	$	3.0	$	10.1
Fair value of units vested	Fair value of units vested	$	18.9	$	12.6	Fair value of units vested	$	10.2	$	18.9

As of March 31, ~~2020,~~2021, there ~~was $37.3~~were $26.6 million of unrecognized compensation ~~cost~~costs that related to non-vested ENLC restricted incentive units. ~~This cost is~~These costs are expected to be recognized over a weighted-average period of 1.9 years.

2220

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 0 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:


		Three Months Ended March 31, 2020							Three Months Ended March 31, 2021
ENLC Performance Units:	ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value		ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	Non-vested, beginning of period	1,317,856		$	14.22	Non-vested, beginning of period	2,351,241		$	8.82
Granted	Granted	1,161,986		7.32		Granted	1,388,139		4.70
Vested (1)	Vested (1)	(160,002)		31.13		Vested (1)	(164,553)		26.73

Non-vested, end of period	Non-vested, end of period	2,319,840		$	9.60	Non-vested, end of period	3,574,827		$	6.40
Aggregate intrinsic value, end of period (in millions)	Aggregate intrinsic value, end of period (in millions)	$	2.6			Aggregate intrinsic value, end of period (in millions)	$	15.3

____________________________

(1)Vested units included ~~60,920~~63,901 units withheld for payroll taxes paid on behalf of employees.


		Three Months Ended March 31,							Three Months Ended March 31,
ENLC Performance Units:	ENLC Performance Units:	2020		2019		ENLC Performance Units:	2021		2020
Aggregate intrinsic value of units vested	Aggregate intrinsic value of units vested	$	0.9	$	1.8	Aggregate intrinsic value of units vested	$	0.6	$	0.9
Fair value of units vested	Fair value of units vested	$	5.0	$	1.9	Fair value of units vested	$	4.4	$	5.0

As of March 31, ~~2020,~~2021, there ~~was $16.8~~were $14.9 million of unrecognized compensation ~~cost~~costs that related to non-vested ENLC performance units. ~~That cost is~~These costs are expected to be recognized over a weighted-average period of 1.8 years.

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

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

d.~~ENLK Restricted Incentive Units~~

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.

Three Months Ended
March 31,

~~ENLK Restricted Incentive Units:~~

~~2019~~

~~Aggregate intrinsic value of units vested~~

~~8.0~~

~~Fair value of units vested~~

~~7.2~~

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

e.~~ENLK Performance Units~~

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.

Three Months Ended
March 31,

~~ENLK Performance Units:~~

~~2019~~

~~Aggregate intrinsic value of units vested~~

~~2.1~~

~~Fair value of units vested~~

~~1.7~~


ENLC Performance Units:	January 2021			July 2020			March 2020			January 2020
Grant-Date Fair Value	$	4.70		$	2.33		$	1.13		$	7.69
Beginning TSR price	$	3.71		$	2.52		$	1.25		$	6.13
Risk-free interest rate	0.17		%	0.17		%	0.42		%	1.62		%
Volatility factor	71.00		%	67.00		%	51.00		%	37.00		%

~~(12)~~(11) Derivatives

Interest Rate Swaps

In April 2019, we entered into an $850.0 million of interest rate ~~swap~~swaps 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.

In December 2020, in connection with the partial repayment of the Term Loan, we paid $10.9 million to terminate $500.0 million of the $850.0 million interest rate swaps and settled the outstanding derivative liability of $10.9 million. The unrealized loss remains in accumulated other comprehensive loss and will amortize into “Interest expense” on the consolidated statements of operations until the original maturity date of the Term Loan. For the three months ended March 31, ~~2020,~~2021, we ~~recorded $13.1~~amortized $2.9 million ~~net~~into interest expense out of ~~a tax benefit of $4.0 million, into~~ accumulated other comprehensive ~~loss~~income (loss) related to the termination of

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

the interest rate swaps. The remaining $350.0 million interest rate swaps were re-designated as a cash flow hedge on LIBOR-based borrowings and continue to be effective.

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


	Three Months Ended March 31,
	2021		2020
Change in fair value of interest rate swaps	$	4.7	$	(17.1)
Tax benefit (expense)	(1.1)		4.0
Gain (loss) on designated cash flow hedge	$	3.6	$	(13.1)

~~For the three months ended March 31, 2020, we realized a~~The interest expense, recognized from accumulated other comprehensive loss ~~of $1.3 million related to~~from the monthly ~~settlements~~settlement of our interest rate swaps ~~which we recorded into interest expense, net~~and amortization of ~~interest income from accumulated other comprehensive loss.~~ the termination payment, included in our consolidated statements of operations were as follows (in millions):


	Three Months Ended March 31,
	2021		2020
Interest expense	$	4.8	$	1.3

We expect to recognize an additional ~~$16.3~~$13.5 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):

March 31, 2020 December 31, 2019
Fair value of derivative liabilities—current $ (16.1) $ (5.6)
Fair value of derivative liabilities—long-term (13.4) (6.8)
Net fair value of interest rate swaps $ (29.5) $ (12.4)


	March 31, 2021		December 31, 2020


Fair value of derivative liabilities—current	$	(5.7)	$	(7.6)

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
March 31,
2020 2019
Change in fair value of derivatives $ 13.0 $ (2.0)
Realized gain on derivatives 6.2 3.8
Gain on derivative activity $ 19.2 $ 1.8


	Three Months Ended March 31,
	2021		2020
Change in fair value of derivatives	$	(7.9)	$	13.0
Realized gain (loss) on derivatives	(75.5)		6.2
Gain (loss) on derivative activity	$	(83.4)	$	19.2

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


	March 31, 2021		December 31, 2020
Fair value of derivative assets—current	$	40.2	$	25.0
Fair value of derivative assets—long-term	3.4		4.9
Fair value of derivative liabilities—current	(53.6)		(29.5)
Fair value of derivative liabilities—long-term	0		(2.5)
Net fair value of commodity swaps	$	(10.0)	$	(2.1)

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

March 31, 2020 December 31, 2019
Fair value of derivative assets—current $ 75.0 $ 12.9
Fair value of derivative assets—long-term 8.2 4.3
Fair value of derivative liabilities—current (61.8) (8.8)
Net fair value of commodity swaps $ 21.4 $ 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 March 31, ~~2020~~2021 (in millions). The remaining term of the contracts extend no later than December 2022.

March 31, 2020

March 31, 2021

Commodity

Instruments

Unit

Volume

Net Fair Value

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(155.8)

8.9

NGL (short contracts)

Swaps

Gallons

(204.2)

(18.1)

NGL (long contracts)

Swaps

Gallons

8.1

(0.3)

NGL (long contracts)

Swaps

Gallons

30.2

(0.1)

Natural gas (short contracts)

Swaps

MMBtu

(20.3)

0.5

Natural gas (short contracts)

Swaps

MMbtu

(10.8)

(0.3)

Natural gas (long contracts)

Swaps

MMBtu

15.0

(0.5)

Natural gas (long contracts)

Swaps

MMbtu

3.9

0.7

Crude and condensate (short contracts)

Swaps

MMbbls

(13.2)

(46.0)

Crude and condensate (short contracts)

Swaps

MMbbls

(9.5)

(17.6)

Crude and condensate (long contracts)

Swaps

MMbbls

2.1

58.8

Crude and condensate (long contracts)

Swaps

MMbbls

4.3

25.4

Total fair value of commodity swaps

21.4

Total fair value of commodity swaps

(10.0)

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 ~~$83.2~~$43.6 million as of March 31, ~~2020~~2021 would be reduced to ~~$21.4~~$7.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

~~(13)~~(12) Fair Value Measurements

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


		Level 2							Level 2
		March 31, 2020		December 31, 2019			March 31, 2021		December 31, 2020
Interest rate swaps (1)	Interest rate swaps (1)	$	(29.5)	$	(12.4)	Interest rate swaps (1)	$	(5.7)	$	(7.6)
Commodity swaps (2)	Commodity swaps (2)	$	21.4	$	8.4	Commodity swaps (2)	$	(10.0)	$	(2.1)

____________________________

(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.~~820, Fair Value Measurement.

~~Table of Contents~~

~~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):

March 31, 2020 December 31, 2019
Carrying Value Fair
Value Carrying Value Fair
Value
Long-term debt (1) $ 4,954.8 $ 3,021.6 $ 4,764.3 $ 4,444.2


	March 31, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,495.0	$	4,207.7	$	4,593.8	$	4,318.2

____________________________

(1)The carrying value of long-term debt includes current maturities and is reduced by debt issuance costs of ~~$28.8~~$31.5 million and ~~$29.8~~$32.6 million as of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, 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 March 31, ~~2020~~2021 and December 31, ~~2019~~2020 were based on Level 2 inputs from third-party market quotations.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(14)~~(13) Segment Information

Starting in the first quarter of 2021, we began evaluating the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Commodity swaps activity was previously reported in the Corporate segment. We have recast segment information for all presented periods prior to the first quarter of 2021 to conform to current period presentation. 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;~~Mexico;

•~~North Texas~~Louisiana Segment. The ~~North Texas~~Louisiana segment includes our natural gas ~~gathering,~~and NGL pipelines, natural gas processing plants, natural gas and ~~transmission activities~~NGL storage facilities, and fractionation facilities located in ~~North Texas;~~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;

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

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

We evaluate the performance of our operating segments based on segment ~~profits.~~profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. Summarized financial information for our reportable segments is shown in the following tables (in millions):


		Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2020
Three Months Ended March 31, 2021														Three Months Ended March 31, 2021
Natural gas sales	Natural gas sales	$	15.1	$	20.1	$	41.1	$	81.6	$	—	$	157.9	Natural gas sales	$	125.0	$	121.2	$	35.9	$	51.0	$	0	$	333.1
NGL sales	NGL sales	0.2		0.3		1.2		373.7		—		375.4		NGL sales	0		626.0		0.6		1.2		0		627.8
Crude oil and condensate sales	Crude oil and condensate sales	285.0		—		16.2		58.4		—		359.6		Crude oil and condensate sales	107.3		41.1		13.6		0		0		162.0

Product sales	Product sales	300.3		20.4		58.5		513.7		—		892.9		Product sales	232.3		788.3		50.1		52.2		0		1,122.9

NGL sales—related parties	NGL sales—related parties	45.9		17.2		67.6		6.8		(137.6)		(0.1)		NGL sales—related parties	164.9		23.6		113.1		80.9		(382.5)		0
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	0.1		1.5		(0.2)		—		(1.3)		0.1		Crude oil and condensate sales—related parties	0		0		0		1.5		(1.5)		0
Product sales—related parties	Product sales—related parties	46.0		18.7		67.4		6.8		(138.9)		—		Product sales—related parties	164.9		23.6		113.1		82.4		(384.0)		0
Gathering and transportation	Gathering and transportation	16.3		45.9		56.3		11.7		—		130.2		Gathering and transportation	9.7		15.8		51.3		40.4		0		117.2
Processing	Processing	4.3		35.4		33.3		0.7		—		73.7		Processing	8.2		0.5		15.9		27.1		0		51.7
NGL services	NGL services	—		—		—		19.6		—		19.6		NGL services	0		22.0		0		0.1		0		22.1
Crude services	Crude services	4.2		—		4.3		10.6		—		19.1		Crude services	3.5		9.9		3.3		0.2		0		16.9
Other services	Other services	0.6		0.3		0.1		0.4		—		1.4		Other services	0.2		0.5		0.2		0.1		0		1.0
Midstream services	Midstream services	25.4		81.6		94.0		43.0		—		244.0		Midstream services	21.6		48.7		70.7		67.9		0		208.9

Crude services—related parties	Crude services—related parties	—		—		0.1		—		(0.1)		—		Crude services—related parties	0		0		0.1		0		(0.1)		0

Other services—related parties														Other services—related parties	0		2.3		0		0		(2.3)		0
Midstream services—related parties	Midstream services—related parties	—		—		0.1		—		(0.1)		—		Midstream services—related parties	0		2.3		0.1		0		(2.4)		0
Revenue from contracts with customers	Revenue from contracts with customers	371.7		120.7		220.0		563.5		(139.0)		1,136.9		Revenue from contracts with customers	418.8		862.9		234.0		202.5		(386.4)		1,331.8
Cost of sales		(313.9)		(27.0)		(93.7)		(459.7)		139.0		(755.3)
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)														Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(325.6)		(740.4)		(151.0)		(104.1)		386.4		(934.7)
Realized loss on derivatives														Realized loss on derivatives	(56.9)		(10.7)		(6.0)		(1.9)		0		(75.5)
Change in fair value of derivatives														Change in fair value of derivatives	(5.3)		(0.4)		(1.8)		(0.4)		0		(7.9)
Adjusted gross margin														Adjusted gross margin	31.0		111.4		75.2		96.1		0		313.7
Operating expenses	Operating expenses	(25.5)		(20.5)		(22.9)		(31.8)		—		(100.7)		Operating expenses	11.8		(29.2)		(19.7)		(19.2)		0		(56.3)
Gain on derivative activity		—		—		—		—		19.2		19.2
Segment profit	Segment profit	$	32.3	$	73.2	$	103.4	$	72.0	$	19.2	$	300.1	Segment profit	42.8		82.2		55.5		76.9		0		257.4
Depreciation and amortization	Depreciation and amortization	$	(29.2)	$	(37.2)	$	(56.6)	$	(37.8)	$	(2.0)	$	(162.8)	Depreciation and amortization	(33.5)		(36.1)		(50.7)		(28.7)		(2.0)		(151.0)
Impairments		$	(184.6)	$	—	$	—	$	(168.4)	$	—	$	(353.0)

Gain (loss) on disposition of assets														Gain (loss) on disposition of assets	0.1		(0.1)		0		0		0		0
General and administrative														General and administrative	0		0		0		0		(26.0)		(26.0)
Interest expense, net of interest income														Interest expense, net of interest income	0		0		0		0		(60.0)		(60.0)

Loss from unconsolidated affiliates														Loss from unconsolidated affiliates	0		0		0		0		(6.3)		(6.3)
Other expense														Other expense	0		0		0		0		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes														Income (loss) before non-controlling interest and income taxes	$	9.4	$	46.0	$	4.8	$	48.2	$	(94.4)	$	14.0
Capital expenditures	Capital expenditures	$	86.0	$	4.7	$	8.5	$	15.2	$	0.4	$	114.8	Capital expenditures	$	13.3	$	2.8	$	1.9	$	2.4	$	0.4	$	20.8

____________________________

(1)Includes related party cost of sales of $3.2 million for the three months ended March 31, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $149.0 million for the three months ended March 31, 2021.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)


		Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2019
Three Months Ended March 31, 2020														Three Months Ended March 31, 2020
Natural gas sales	Natural gas sales	$	36.1	$	50.6	$	61.6	$	122.2	$	—	$	270.5	Natural gas sales	$	15.1	$	81.6	$	41.1	$	20.1	$	0	$	157.9
NGL sales	NGL sales	(0.2)		9.3		8.9		573.1		—		591.1		NGL sales	0.2		373.7		1.2		0.3		0		375.4
Crude oil and condensate sales	Crude oil and condensate sales	580.8		—		29.6		58.8		—		669.2		Crude oil and condensate sales	285.0		58.4		16.2		0		0		359.6
Other		—		—		0.1		—		—		0.1

Product sales	Product sales	616.7		59.9		100.2		754.1		—		1,530.9		Product sales	300.3		513.7		58.5		20.4		0		892.9

NGL sales—related parties	NGL sales—related parties	97.2		28.5		126.1		3.2		(255.0)		—		NGL sales—related parties	45.9		6.8		67.6		17.2		(137.6)		(0.1)
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	4.0		1.0		—		—		(5.0)		—		Crude oil and condensate sales—related parties	0.1		0		(0.2)		1.5		(1.3)		0.1
Product sales—related parties	Product sales—related parties	101.2		29.5		126.1		3.2		(260.0)		—		Product sales—related parties	46.0		6.8		67.4		18.7		(138.9)		0
Gathering and transportation	Gathering and transportation	10.3		63.6		55.3		17.2		—		146.4		Gathering and transportation	16.3		11.7		56.3		45.9		0		130.2
Processing	Processing	7.7		21.1		34.1		0.9		—		63.8		Processing	4.3		0.7		33.3		35.4		0		73.7
NGL services	NGL services	—		—		—		11.7		—		11.7		NGL services	0		19.6		0		0		0		19.6
Crude services	Crude services	5.2		—		4.0		13.8		—		23.0		Crude services	4.2		10.6		4.3		0		0		19.1
Other services	Other services	1.5		0.2		(0.3)		0.2		—		1.6		Other services	0.6		0.4		0.1		0.3		0		1.4
Midstream services	Midstream services	24.7		84.9		93.1		43.8		—		246.5		Midstream services	25.4		43.0		94.0		81.6		0		244.0

NGL services—related parties		—		—		—		(3.0)		3.0		—

Crude services—related parties	Crude services—related parties	—		—		0.3		—		(0.3)		—		Crude services—related parties	0		0		0.1		0		(0.1)		0

Midstream services—related parties	Midstream services—related parties	—		—		0.3		(3.0)		2.7		—		Midstream services—related parties	0		0		0.1		0		(0.1)		0
Revenue from contracts with customers	Revenue from contracts with customers	742.6		174.3		319.7		798.1		(257.3)		1,777.4		Revenue from contracts with customers	371.7		563.5		220.0		120.7		(139.0)		1,136.9
Cost of sales		(676.2)		(73.7)		(184.2)		(686.6)		257.3		(1,363.4)
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)														Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(313.9)		(459.7)		(93.7)		(27.0)		139.0		(755.3)
Realized gain on derivatives														Realized gain on derivatives	0.9		4.3		0.8		0.2		0		6.2
Change in fair value of derivatives														Change in fair value of derivatives	9.4		(1.0)		3.8		0.8		0		13.0
Adjusted gross margin														Adjusted gross margin	68.1		107.1		130.9		94.7		0		400.8
Operating expenses	Operating expenses	(27.8)		(25.7)		(25.4)		(35.6)		—		(114.5)		Operating expenses	(25.5)		(31.8)		(22.9)		(20.5)		0		(100.7)
Gain on derivative activity		—		—		—		—		1.8		1.8
Segment profit	Segment profit	$	38.6	$	74.9	$	110.1	$	75.9	$	1.8	$	301.3	Segment profit	42.6		75.3		108.0		74.2		0		300.1
Depreciation and amortization	Depreciation and amortization	$	(27.9)	$	(34.3)	$	(46.1)	$	(41.8)	$	(2.0)	$	(152.1)	Depreciation and amortization	(29.2)		(37.8)		(56.6)		(37.2)		(2.0)		(162.8)
Impairments	Impairments	$	—	$	—	$	—	$	(186.5)	$	—	$	(186.5)	Impairments	(184.6)		(168.4)		0		0		0		(353.0)
Goodwill		$	184.6	$	125.7	$	813.4	$	—	$	—	$	1,123.7
Gain on disposition of assets														Gain on disposition of assets	0.4		0		0.2		0		0		0.6
General and administrative														General and administrative	0		0		0		0		(30.4)		(30.4)
Interest expense, net of interest income														Interest expense, net of interest income	0		0		0		0		(55.6)		(55.6)
Gain on extinguishment of debt														Gain on extinguishment of debt	0		0		0		0		5.3		5.3
Income from unconsolidated affiliates														Income from unconsolidated affiliates	0		0		0		0		1.7		1.7

Income (loss) before non-controlling interest and income taxes														Income (loss) before non-controlling interest and income taxes	$	(170.8)	$	(130.9)	$	51.6	$	37.0	$	(81.0)	$	(294.1)

Capital expenditures	Capital expenditures	$	95.9	$	4.3	$	108.2	$	41.0	$	1.6	$	251.0	Capital expenditures	$	86.0	$	15.2	$	8.5	$	4.7	$	0.4	$	114.8

____________________________

~~The following table reconciles~~(1)Includes related party cost of sales of $2.9 million for the ~~segment profits reported above~~three months ended March 31, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $160.8 million for the ~~operating loss as reported on the consolidated statements of operations (in millions):~~three months ended March 31, 2020.

Three Months Ended
March 31,
2020 2019
Segment profit $ 300.1 $ 301.3
General and administrative expenses (30.4) (51.4)
Gain on disposition of assets 0.6 —
Depreciation and amortization (162.8) (152.1)
Impairments (353.0) (186.5)
Operating loss $ (245.5) $ (88.7)

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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 March 31, ~~2020~~2021 and December 31, ~~2019~~2020 (in millions):


Segment Identifiable Assets:	Segment Identifiable Assets:	March 31, 2020		December 31, 2019		Segment Identifiable Assets:	March 31, 2021		December 31, 2020
Permian	Permian	$	2,362.3	$	2,465.7	Permian	$	2,292.8	$	2,236.3
Louisiana						Louisiana	2,316.7		2,312.4
Oklahoma						Oklahoma	2,743.8		2,847.6
North Texas	North Texas	1,091.0		1,135.8		North Texas	986.0		1,008.6
Oklahoma		2,974.6		3,035.0
Louisiana		2,233.9		2,562.0
Corporate(1)	Corporate(1)	393.3		137.3		Corporate(1)	177.0		146.0
Total identifiable assets	Total identifiable assets	$	9,055.1	$	9,335.8	Total identifiable assets	$	8,516.3	$	8,550.9

____________________________

(1)Accounts receivable and accrued revenue sold to the SPV for collateral under the AR Facility are included within the Permian, Louisiana, Oklahoma, and North Texas segments.

~~(15)~~(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:	Other current assets:	March 31, 2020		December 31, 2019		Other current assets:	March 31, 2021		December 31, 2020
Natural gas and NGLs inventory	Natural gas and NGLs inventory	$	7.3	$	43.4	Natural gas and NGLs inventory	$	36.8	$	44.9
Prepaid expenses and other	Prepaid expenses and other	11.7		14.4		Prepaid expenses and other	28.8		13.8
Other current assets	Other current assets	$	19.0	$	57.8	Other current assets	$	65.6	$	58.7


Other current liabilities:	Other current liabilities:	March 31, 2020		December 31, 2019		Other current liabilities:	March 31, 2021		December 31, 2020
Accrued interest	Accrued interest	$	69.2	$	37.1	Accrued interest	$	74.1	$	35.7
Accrued wages and benefits, including taxes	Accrued wages and benefits, including taxes	16.1		31.5		Accrued wages and benefits, including taxes	8.8		22.5
Accrued ad valorem taxes	Accrued ad valorem taxes	17.0		28.5		Accrued ad valorem taxes	12.1		26.5
Capital expenditure accruals	Capital expenditure accruals	45.0		42.4		Capital expenditure accruals	8.7		10.6
Retention liability		8.9		8.7
Short-term lease liability	Short-term lease liability	17.6		21.1		Short-term lease liability	19.2		16.3
Suspense producer payments		13.8		13.8
Operating expense accruals	Operating expense accruals	9.5		10.8		Operating expense accruals	17.8		8.4
Other	Other	19.7		12.3		Other	25.2		29.1
Other current liabilities	Other current liabilities	$	216.8	$	206.2	Other current liabilities	$	165.9	$	149.1

(15) Commitments and Contingencies

In February 2021, the areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days (“Winter Storm Uri”). As a result of Winter Storm Uri, we have several pending customer billing disputes, including one that has resulted in litigation, and we could be involved in other disputes and litigation arising out of the storm in the future.

We are involved in various litigation and administrative proceedings arising in the normal course of business. We cannot currently predict the outcome of these contingencies and therefore have not accrued any costs associated with potential claims. In the opinion of management, any liabilities that may result from these claims would not individually or in aggregate have a material adverse effect on our financial position, results of operations, or cash flows.

(16) Subsequent Event

~~Current Market Environment.~~Amarillo Rattler Acquisition. On ~~March 11, 2020,~~April 30, 2021, we completed the ~~World Health Organization declared~~acquisition of Amarillo Rattler, LLC, the ~~ongoing coronavirus (COVID-19) outbreak~~owner of a ~~pandemic~~gathering and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the energy industry as a whole and midstream companies, and on our employees, 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 significant reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for crude oil has dropped by nearly one-third since mid-February. The decline in demand has been met with a declineprocessing system located in the ~~market price for these commodities, particularly for crude oil,~~Midland Basin. In connection with the purchase, we entered into an amended and ~~especially following~~restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position and deepening our relationship with Diamondback Energy. We acquired the ~~announcement by Saudi Arabia~~system with an upfront payment of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire. On April 12, 2020, members of OPEC+ agreed to certain production cuts; however, these cuts are not expected$50.0 million, which was paid with cash-on-hand, with an additional $10 million to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for oil and significantly higher costs for available storage. In the case of the oil markets, both the declinepaid in ~~demand and storage concerns have caused the price of oil to reach historic lows.~~

~~As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity,~~2022, and an ~~uncertain timeline for recovery, oil and natural gas producers, including our customers, have sharply curtailed their current~~earnout capped at $15 million based on Diamondback Energy’s drilling ~~and production~~

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

activity as well as their plans for future drilling and production activity. As a result of these decreases in activity, our business and financial results, and those of others in our industry, have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets as a result of reduced production from the regions that supply our systems. We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, or cash flows (including our ability to make distributions to our unitholders) at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak and the governmental measures designed to contain the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, the availability of oil storage capacity, and the timing and extent to which normal economic and operating conditions resume.

above historical levels.

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

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

Overview

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

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

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

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

Our midstream energy asset network includes approximately ~~12,000~~11,900 miles of pipelines, 2122 natural gas processing plants with approximately ~~5.3~~5.5 Bcf/d of processing capacity, ~~seven~~7 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.

Starting in the first quarter of 2021, we began evaluating the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Commodity swaps activity was previously reported in the Corporate segment. We have ~~five reportable segments:~~recast segment information for all presented periods prior to the first quarter of 2021 to conform to current period presentation. Identification of the majority of our operating segments is based principally upon geographic regions served:

We manage our consolidated operations by focusing on adjusted 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

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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~~Adjusted 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 ~~89%~~82% of our adjusted gross ~~operating~~ margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the three months ended March 31, ~~2020. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.~~

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2021.

Devon is one of our primary customers. For the three months ended March 31, 2020 and 2019, approximately 33.4% and 30.0% of our gross operating margin, respectively, was attributable to commercial contracts with Devon.

Our revenues and adjusted 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.

The following 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 adjusted gross margin received from transactions with these customers is material to us.


	Three Months Ended March 31,
	2021		2020
Devon	9.6	%	12.9	%
Dow Hydrocarbons and Resources LLC	14.5	%	11.2	%
Marathon Petroleum Corporation	14.8	%	16.8	%

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 adjusted 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 adjusted 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~~based contracts, or a

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combination of these contractual arrangements. ~~“See Item~~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 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 adjusted gross ~~operating~~ margins are higher during periods of high NGL prices relative to natural gas prices. ~~Gross operating~~Adjusted gross 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~~Adjusted gross 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 adjusted 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

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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

Current Market Environment

The midstream energy business environment and our business are affected by the level of production of natural gas and oil in the areas in which we operate and the various factors that affect this production, including commodity prices, capital markets trends, competition, and regulatory changes. We believe these factors will continue to affect production and therefore the demand for midstream services and our business in the future. To the extent these factors vary from our underlying assumptions, our business and actual results could vary materially from market expectations and from the assumptions discussed in this section.

Production levels by our exploration and production customers are driven in large part by the level of oil and natural gas prices. New drilling activity is necessary to maintain or increase production levels as oil and natural gas wells experience production declines over time. New drilling activity generally moves in the same direction as crude oil and natural gas prices as those prices drive investment returns and cash flow available for reinvestment by exploration and production companies. Accordingly, our operations are affected by the level of crude, natural gas, and NGL prices, the relationship among these prices, and related activity levels from our customers.

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. During 2020, the COVID-19 pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, led to a reduction in global demand for energy, volatility in the market prices for crude oil, condensate, natural gas, and NGLs, and a significant reduction in the market price of crude oil during the first half of 2020. Although commodity markets have recovered nearly to pre-pandemic levels, oil and natural gas commodity prices remain somewhat weak relative to historical levels and continue to remain volatile.

Capital markets and the demands of public investors also affect producer behavior, production levels, and our business. Over the last several years, public investors have exerted pressure on oil and natural gas producers to increase capital discipline and focus on higher investment returns even if it means lower growth. In addition, the ability of companies in the oil and gas industry to access the capital markets on favorable terms has been negatively impacted. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, has led to more modest capital investment by producers, curtailed drilling and production activity, and, accordingly, slower growth for us and other midstream companies during the past few years. This trend was amplified in 2020 as a result of the COVID-19 pandemic demand destruction. Although volumes recovered nearly to pre-pandemic levels in the second half of 2020, global capital investments by oil and natural gas producers remain at low levels.

Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In the last few years, many producers have increasingly focused their activities in the Permian Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating in the United States are operating in the Permian Basin. As a result of this concentration of drilling activity in the Permian, other basins, including those in which we operate in Oklahoma and North Texas, have experienced reduced incremental new investment and declines in volumes produced. In contrast, we continue to experience an increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity.

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Our Louisiana segment, while subject to commodity prices and capital markets developments, is less dependent on gathering and processing activities and more affected by industrial demand for the natural gas and NGLs that we supply. Industrial demand along the Gulf Coast region has remained strong in the second half of 2020 and through the first quarter of 2021, supported by regional industrial activity and export markets. Our activities and, in turn, our financial performance in the Louisiana segment are highly dependent on the availability of natural gas and NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to supply our customers, and maintaining such supply is a key business focus.

For additional discussion regarding these factors, see “Item 1A—Risk Factors—Business and Industry Risks” in our Annual Report on Form 10-K filed with the Commission on February 17, 2021.

Winter Storm Uri

In February 2021, the areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days (“Winter Storm Uri”). Winter Storm Uri adversely affected the Company’s facilities and activities across the Company’s footprint, as it did for producers and other midstream companies located in these areas. The severe cold temperatures caused production freeze-offs and also led some producers to proactively shut-in their wells to preserve well integrity. As a result, the Company’s gathering and processing volumes were significantly reduced during this period, with peak volume declines ranging between 44% and 92%, depending on the region. The Company responded to the challenges presented by the storm by taking active steps to ensure the resiliency of the Company’s assets and the protection of the health and well-being of its employees. The Company’s operations have now returned to normal, and volumes have recovered to pre-storm levels.

The lack of gathered and processed volumes during the storm presented a number of commercial challenges, including the management of losses on derivative contracts and firm commodity sales contracts and making outlays to meet one-time operating expenses for storm recovery. To balance these challenges, the Company was able to use its integrated asset base to make limited incremental gas available to support local markets and to use its storage volumes in Louisiana to help offset lower natural gas and NGL supplies. Additionally, because of idled operations and elevated power prices, the Company was able to earn approximately $40 million in credits for unused electricity which had been purchased on a firm basis. These credits can be used to offset future power payments. However, because of the magnitude and unprecedented nature of the storm, we cannot at this time predict the full impact that Winter Storm Uri may have on our future results of operations. The ultimate impacts will depend on future developments, including, among other factors, the outcome of pending billing disputes with customers and regulatory actions by state legislatures and other entities responsible for the regulation and pricing of electricity and the electrical grid.

COVID-19 Update

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 more than 200 countries and has resulted in widespread adverse impacts on~~Since the ~~global economy, the energy industry as a whole and midstream companies, and on~~outbreak began, our employees, 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 significant reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for oil has dropped by nearly one-third since mid-February. The decline in demand has been met with a decline in the market price for these commodities, particularly for crude oil, and especially following the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire on April 1, 2020, and the ensuing expiration thereof. On April 12, 2020, members of OPEC+ agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for oil and significantly higher costs for available storage. In the case of the oil markets, both the decline in demand and storage concerns have caused the price of oil to reach historic lows.

As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity, and an uncertain timeline for recovery, oil and natural gas producers, including our customers, have sharply curtailed their current drilling and production activity as well as their plans for future drilling and production activity. This reduction in production has been most acute for crude oil production, but because condensate production and a significant portion of gas and NGL production depends on, or is a byproduct of, the production of crude oil, the curtailment of crude oil drilling and production affects the production of these other commodities. As a result of these decreases in producer activity, our business and financial results, and those of others in our industry, have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets as a result of reduced production from the regions that supply our systems. Our first priority ~~in our response to this crisis~~ has been the health and safety of our employees and those of our customers and other business counterparties. ~~We have~~Beginning in March 2020, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ ~~operations. We have a crisis management team for health, safety and environmental matters and personnel issues,~~operations, and we ~~have established a cross-functional COVID-19 response team~~continue to ~~address various impacts of the situation, as they have been developing.~~follow these plans. We also have modified certain business practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employees who can execute their work remotely, and encouraging employeescontinue 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 promotedpromote heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and ~~operations.~~operations and we continue to evaluate and adjust our preventative measures, response plans, and business practices with the evolving impacts of COVID-19. We have continued to maintain these COVID protocols since the inception of the pandemic and to date we have not experienced any COVID-19 related operational disruptions.

There is considerable uncertainty regarding how long the ~~extent to which~~ COVID-19 pandemic will ~~continue to spread~~persist and affect economic conditions and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how significantly and how long they will continue to affect us. We expect to see continued volatility in crude oil, condensate, natural gas, and NGL prices for the foreseeable future, which may, over the long term, adversely impact our business. A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreaseschanges 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. We have also moved quickly and decisively to implement strategies to reduce costs, increase operational efficiencies, and lower our capital spending. As we previously announced, we intend to reduce our capital expenditures in 2020, including both growth and maintenance capital expenditures, to between $190 million and $250 million, a 65% reduction from 2019 total capital spending. We have also reduced costs across our platform and we intend to reduce our general and administrative and operational expenses by $100 million for the full-year 2020 versus the twelve months ended December 31, 2019. In addition, we maintain

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our previously announced plan to fully self-fund all capital expenditures during 2020 with internally generated cash flows, and have no plans to access the capital markets during 2020. Also, as of March 31, 2020, we had approximately $258 million of cash on our balance sheet and have drawn only approximately $550 million on our $1.75 billion ENLC 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.behavior.

We cannot predict the full impact that the COVID-19 pandemic or the ~~significant disruption and~~ volatility ~~currently being experienced~~ in ~~the~~ oil and natural gas markets related to COVID-19 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 ~~geographic spread~~duration and persistence of the pandemic, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the effect of the pandemic 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 of effective treatments, the duration of the outbreak, and the governmental measures designed to contain~~ the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, ~~workforce availability, the availability of oil storage capacity,~~ and the timing and extent to which normal economic, social, and operating conditions resume. A sustained significant decline in oil and natural gas exploration and production activities and

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Werelated reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for crude oil, condensate, natural gas, and NGLs or otherwise, would have ~~revised~~a material adverse effect on our ~~forecasts~~business, liquidity, financial condition, results of operations, and ~~as a result have recorded impairments of goodwill and property and equipment during the three months ended March 31, 2020. We will continue~~cash flows (including our ability to ~~monitor the market environment and will evaluate whether additional triggering events would indicate possible impairments of property and equipment and intangible assets.~~make distributions to our unitholders).

For additional discussion regarding risks associated with the COVID-19 pandemic, see ~~Part II, Item~~“Item 1A—Risk Factors—The ongoing coronavirus (COVID-19) pandemic has adversely affected and could continue to adversely affect our business, financial condition, and results of operations” in our Annual Report on Form 10-K filed with the Commission on February 17, 2021.

Regulatory Developments

On January 20, 2021, the Biden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers. On his first day in office, President Biden signed an instrument reentering the United States into the Paris Agreement, effective February 19, 2021, and issued an executive order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. In addition, on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, and on April 22, 2021, at a global summit on climate change, President Biden committed the United States to target emissions reductions of 50-52% of 2005 levels by 2030. Among the areas that could be affected by these initiatives are regulations addressing methane emissions and the part of the extraction process known as hydraulic fracturing. The Biden Administration could also seek, in the future, to put into place additional executive orders, policy and regulatory reviews, or seek to have Congress pass legislation that could adversely affect the production of oil and gas assets and our operations and those of our customers.

Only a small percentage of our operations are derived from customers operating on public land, mainly in the Delaware Basin, and these activities are expected to represent only approximately 4% of our total segment profit, net to EnLink, during 2021. In addition, we have a robust program to monitor and prevent methane emissions in our operations and we maintain a comprehensive environmental program that is embedded in our operations. However, our activities that take place on public lands require that we and our producer customers obtain leases, permits, and other approvals from the federal government. While the status of recent and future rules and rulemaking initiatives under the Biden Administration remain uncertain, these actions, and the regulations and the policies that could result from them, could lead to increased costs for us or our customers, difficulties in obtaining leases, permits, and other approvals for us and our customers, reduced utilization of our gathering, processing and pipeline systems or reduced rates under renegotiated transportation or storage agreements in affected regions. These impacts could, in turn, adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders.

For more information, see our risk factors under “Environmental, Legal Compliance, and Regulatory Risk” in Section 1A “Risk Factors” in ~~this report.~~our Annual Report on Form 10-K filed with the Commission on February 17, 2021.

~~Other Recent Developments~~

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

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

Non-GAAP Financial Measures

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

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization related to our operating segments. We present adjusted gross margin by segment in “Results of Operations.” We disclose adjusted gross margin in addition to gross margin as defined by GAAP because it is the primary performance measure used by our management to evaluate consolidated operations. We believe adjusted gross 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 the 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 exclude all operating expenses and depreciation and amortization related to our operating segments from adjusted gross 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 adjusted gross margin is gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin as determined in accordance with GAAP. Adjusted gross margin has important limitations because it excludes all operating expenses and depreciation and amortization related to our operating segments that affect gross margin. Our adjusted gross 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 reconciles total revenues and gross margin to adjusted gross margin (in millions):


	Three Months Ended March 31,
	2021		2020
Total revenues	$	1,248.4	$	1,156.1
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(934.7)		(755.3)
Operating expenses	(56.3)		(100.7)
Depreciation and amortization	(151.0)		(162.8)
Gross margin	106.4		137.3
Operating expenses	56.3		100.7
Depreciation and amortization	151.0		162.8
Adjusted gross margin	$	313.7	$	400.8

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(1)Excludes all operating expenses as well as depreciation and amortization related to our operating segments of $149.0 million and $160.8 million for the three months ended March 31, 2021 and 2020, respectively.

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Adjusted EBITDA

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

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

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

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

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

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

Adjusted EBITDA does not include interest expense, net of interest income; income tax expense (benefit); and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we ~~use~~have 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.

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


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
Net loss		$	(260.4)	$	(134.8)
Net income (loss)						Net income (loss)	$	12.6	$	(260.4)
Interest expense, net of interest income	Interest expense, net of interest income	55.6		49.6		Interest expense, net of interest income	60.0		55.6
Depreciation and amortization	Depreciation and amortization	162.8		152.1		Depreciation and amortization	151.0		162.8
Impairments	Impairments	353.0		186.5		Impairments	—		353.0
Income from unconsolidated affiliates		(1.7)		(5.3)
(Income) loss from unconsolidated affiliates						(Income) loss from unconsolidated affiliates	6.3		(1.7)
Distributions from unconsolidated affiliates	Distributions from unconsolidated affiliates	1.8		2.5		Distributions from unconsolidated affiliates	3.6		1.8

Gain on extinguishment of debt	Gain on extinguishment of debt	(5.3)		—		Gain on extinguishment of debt	—		(5.3)
Unit-based compensation	Unit-based compensation	8.8		11.1		Unit-based compensation	6.5		8.8
Income tax expense (benefit)	Income tax expense (benefit)	(33.7)		1.8		Income tax expense (benefit)	1.4		(33.7)
Unrealized (gain) loss on commodity swaps	Unrealized (gain) loss on commodity swaps	(13.0)		2.0		Unrealized (gain) loss on commodity swaps	7.9		(13.0)
Payments under onerous performance obligation offset to other current and long-term liabilities		—		(4.5)
Transaction costs (1)		—		13.5
Relocation costs associated with the War Horse processing facility (1)						Relocation costs associated with the War Horse processing facility (1)	7.6		—
Other (2)	Other (2)	(0.7)		0.3		Other (2)	(0.4)		(0.7)
Adjusted EBITDA before non-controlling interest	Adjusted EBITDA before non-controlling interest	267.2		274.8		Adjusted EBITDA before non-controlling interest	256.5		267.2
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(7.2)		(6.6)		Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(7.1)		(7.2)
Adjusted EBITDA, net to ENLC	Adjusted EBITDA, net to ENLC	$	260.0	$	268.2	Adjusted EBITDA, net to ENLC	$	249.4	$	260.0

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(1)Represents ~~transaction costs attributable to costs~~cost incurred related to the ~~Merger~~relocation of equipment and facilities from the Battle Ridge processing plant, in ~~January 2019.~~the Oklahoma segment, to the Permian segment that we expect to complete in 2021 and are not part of our ongoing operations.

(2)Includes (gain) loss on disposition of assets; accretion expense associated with asset retirement ~~obligations, gain on disposition of assets,~~obligations; and non-cash rent, which relates to lease incentives pro-rated over the lease term.

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

~~Distributable~~

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Free Cash Flow ~~and Excess Free Cash Flow~~After Distributions

We define ~~distributable~~free cash flow after distributions as adjusted EBITDA, net to ENLC, less interest expense, interest rate swaps, current income taxes and other non-distributable cash flows, accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid, and maintenanceplus (less) (growth capital expenditures, excluding ~~maintenance~~ capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated ~~entities. Excess free cash flow is defined as distributable cash flow less distributions declared on common units and growth~~entities); (maintenance 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.~~entities); (interest expense, net of interest income); (distributions declared on common units); (accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid); (relocation costs associated with the War Horse processing facility); (payments to terminate interest rate swaps); non-cash interest (income)/expense; (current income taxes); and proceeds from the sale of equipment and land.

~~Distributable~~Free cash flow ~~and excess free~~after distributions is the principal cash flow ~~are~~metric used by the Company in its earnings announcements. It is also used as a supplemental liquidity ~~measures~~measure 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~~pay back our indebtedness, make cash distributions, and make capital expenditures.

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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~~free cash flow ~~and excess free cash flow~~after distributions is net cash provided by operating activities. ~~Distributable~~Free cash flow ~~and excess free cash flow~~after distributions should not be considered ~~alternatives~~an alternative 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~~Free cash flow ~~and excess free cash flow have~~after distributions has important limitations because ~~they exclude~~it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. ~~Distributable~~Free cash flow ~~and excess free cash flow~~after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate ~~these~~this non-GAAP ~~metrics~~metric 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~~free cash flow ~~and excess free cash flow,~~after distributions, to evaluate our overall liquidity.

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


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
Net cash provided by operating activities	Net cash provided by operating activities	$	182.0	$	264.0	Net cash provided by operating activities	$	225.8	$	182.0
Interest expense (1)	Interest expense (1)	54.7		49.5		Interest expense (1)	55.9		54.7
Current income tax expense		0.3		1.0

Transaction costs (2)		—		13.5
Other (3)		5.6		(1.5)
Utility credits (2)						Utility credits (2)	40.4		—
Accruals for settled commodity swap transactions						Accruals for settled commodity swap transactions	0.1		5.0
Distributions from unconsolidated affiliate investment in excess of earnings						Distributions from unconsolidated affiliate investment in excess of earnings	3.6		0.2
Relocation costs associated with the War Horse processing facility (3)						Relocation costs associated with the War Horse processing facility (3)	7.6		—
Other (4)						Other (4)	1.2		0.7
Changes in operating assets and liabilities which (provided) used cash:	Changes in operating assets and liabilities which (provided) used cash:					Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	Accounts receivable, accrued revenues, inventories, and other	(169.3)		(97.4)		Accounts receivable, accrued revenues, inventories, and other	17.5		(169.3)
Accounts payable, accrued product purchases, and other accrued liabilities (4)		193.9		45.7
Accounts payable, accrued product purchases, and other accrued liabilities						Accounts payable, accrued product purchases, and other accrued liabilities	(95.6)		193.9
Adjusted EBITDA before non-controlling interest	Adjusted EBITDA before non-controlling interest	267.2		274.8		Adjusted EBITDA before non-controlling interest	256.5		267.2
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(7.2)		(6.6)		Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(7.1)		(7.2)
Adjusted EBITDA, net to ENLC	Adjusted EBITDA, net to ENLC	260.0		268.2		Adjusted EBITDA, net to ENLC	249.4		260.0
Growth capital expenditures, net to ENLC (6)						Growth capital expenditures, net to ENLC (6)	(15.9)		(82.6)
Maintenance capital expenditures, net to ENLC (6)						Maintenance capital expenditures, net to ENLC (6)	(4.7)		(8.2)
Interest expense, net of interest income	Interest expense, net of interest income	(55.6)		(49.6)		Interest expense, net of interest income	(60.0)		(55.6)
Maintenance capital expenditures, net to ENLC (6)		(8.2)		(8.5)
Distributions declared on common units						Distributions declared on common units	(46.7)		(46.5)
ENLK preferred unit accrued cash distributions (7)	ENLK preferred unit accrued cash distributions (7)	(22.8)		(22.7)		ENLK preferred unit accrued cash distributions (7)	(23.0)		(22.8)

Relocation costs associated with the War Horse processing facility (3)						Relocation costs associated with the War Horse processing facility (3)	(7.6)		—

Other (8)	Other (8)	(0.3)		(2.5)		Other (8)	2.7		0.2
Distributable cash flow		173.1		184.9
Common distributions declared		(46.5)		(137.3)
Growth capital expenditures, net to ENLC (6)		(82.6)		(219.6)
Excess free cash flow		$	44.0	$	(172.0)
Free cash flow after distributions						Free cash flow after distributions	$	94.2	$	44.5

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(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)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity.

(3)Represents ~~transaction costs attributable to costs~~cost incurred related to the ~~Merger~~relocation of equipment and facilities from the Battle Ridge processing plant, in ~~January 2019.~~the Oklahoma segment, to the Permian segment that we expect to complete in 2021 and are not part of our ongoing operations.

~~(3)~~(4)Includes ~~accruals for settled commodity swap transactions, distributions received from equity method investments to the extent those distributions exceed earnings from the investment,~~current income tax expense; amortization of designated cash flow hedge; and non-cash rent, which relates to lease incentives pro-rated over the lease term.

~~(4)Net of payments under onerous performance obligation offset to other current and long-term liabilities during the three months ended March 31, 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 of $16.8 million and $6.0 million, respectively,~~ Units. See “Item 1. Financial Statements— Note 7” for information on the ~~three months ended March 31, 2020, and~~ cash distributions earned by holders of the Series B Preferred Units and Series C Preferred ~~Units of $16.7 million and $6.0 million, respectively, for the three months ended March 31, 2019.~~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~~(income)/expense; current income tax ~~expense.~~expense; and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business and did not include major divestitures.

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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 loss to gross operating margin (in millions):~~

Three Months Ended
March 31,
2020 2019
Operating loss $ (245.5) $ (88.7)
Add:
Operating expenses 100.7 114.5
General and administrative expenses 30.4 51.4
Gain on disposition of assets (0.6) —
Depreciation and amortization 162.8 152.1
Impairments 353.0 186.5
Gross operating margin $ 400.8 $ 415.8

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Results of Operations

The ~~table~~tables below ~~sets~~set forth certain financial and operating data for the periods indicated. We ~~manage~~evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, ~~which we define as revenue less cost of sales~~ as reflected in the table below (in millions, except volumes):

Three Months Ended
March 31,
2020 2019
Permian Segment
Revenues $ 371.7 $ 742.6
Cost of sales (313.9) (676.2)
Total gross operating margin $ 57.8 $ 66.4
North Texas Segment
Revenues $ 120.7 $ 174.3
Cost of sales (27.0) (73.7)
Total gross operating margin $ 93.7 $ 100.6
Oklahoma Segment
Revenues $ 220.0 $ 319.7
Cost of sales (93.7) (184.2)
Total gross operating margin $ 126.3 $ 135.5
Louisiana Segment
Revenues $ 563.5 $ 798.1
Cost of sales (459.7) (686.6)
Total gross operating margin $ 103.8 $ 111.5
Corporate Segment
Revenues $ (119.8) $ (255.5)
Cost of sales 139.0 257.3
Total gross operating margin $ 19.2 $ 1.8
Total
Revenues $ 1,156.1 $ 1,779.2
Cost of sales (755.3) (1,363.4)
Total gross operating margin $ 400.8 $ 415.8
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d) 831,100 657,500
Processing (MMBtu/d) 861,700 712,000
Crude Oil Handling (Bbls/d) 133,400 147,400
North Texas Segment
Gathering and Transportation (MMBtu/d) 1,577,700 1,683,100
Processing (MMBtu/d) 699,700 729,800
Oklahoma Segment
Gathering and Transportation (MMBtu/d) 1,220,900 1,244,400
Processing (MMBtu/d) 1,154,400 1,231,600
Crude Oil Handling (Bbls/d) 36,600 29,200
Louisiana Segment
Gathering and Transportation (MMBtu/d) 2,043,200 2,070,500
Processing (MMBtu/d) 169,600 468,000
Crude Oil Handling (Bbls/d) 17,400 15,000
NGL Fractionation (Gals/d) 8,184,100 6,973,800
Brine Disposal (Bbls/d) 1,700 3,500


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2021
Gross margin	$	9.3	$	46.1	$	4.8	$	48.2	$	(2.0)	$	106.4

Add:
Depreciation and amortization	33.5		36.1		50.7		28.7		2.0		151.0
Segment profit	42.8		82.2		55.5		76.9		—		257.4
Operating expenses	(11.8)		29.2		19.7		19.2		—		56.3
Adjusted gross margin	$	31.0	$	111.4	$	75.2	$	96.1	$	—	$	313.7


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2020
Gross margin	$	13.4	$	37.5	$	51.4	$	37.0	$	(2.0)	$	137.3

Add:
Depreciation and amortization	29.2		37.8		56.6		37.2		2.0		162.8
Segment profit	42.6		75.3		108.0		74.2		—		300.1
Operating expenses	25.5		31.8		22.9		20.5		—		100.7
Adjusted gross margin	$	68.1	$	107.1	$	130.9	$	94.7	$	—	$	400.8


	Three Months Ended March 31,
	2021	2020
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d)	925,600	831,100
Processing (MMbtu/d)	876,100	861,700
Crude Oil Handling (Bbls/d)	108,200	133,400
Louisiana Segment
Gathering and Transportation (MMbtu/d)	2,151,300	2,043,200

Crude Oil Handling (Bbls/d)	15,000	17,400
NGL Fractionation (Gals/d)	7,106,200	8,184,100
Brine Disposal (Bbls/d)	1,400	1,700
Oklahoma Segment
Gathering and Transportation (MMbtu/d)	937,300	1,220,900
Processing (MMbtu/d)	955,400	1,154,400
Crude Oil Handling (Bbls/d)	17,500	36,600
North Texas Segment
Gathering and Transportation (MMbtu/d)	1,356,900	1,577,700
Processing (MMbtu/d)	624,600	699,700

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Three Months Ended March 31, ~~2020~~2021 Compared to Three Months Ended March 31, ~~2019~~2020

Gross ~~Operating~~ Margin. Gross ~~operating~~ margin was ~~$400.8~~$106.4 million for the three months ended March 31, 2021 compared to $137.3 million for the three months ended March 31, 2020, ~~compared to $415.8 million for the three months ended March 31, 2019,~~ a decrease of ~~$15.0 million, or 3.6%, due~~$30.9 million. The primary contributors to the ~~following:~~decrease were as follows (in millions):

•Permian Segment. Gross ~~operating~~margin was $9.3 million for the three months ended March 31, 2021 compared to $13.4 million for the three months ended March 31, 2020, a decrease of $4.1 million primarily due to the following:

◦Adjusted gross margin in the Permian segment decreased ~~$8.6~~$37.1 million, resulting from (i) a $7.6 million decrease in gross operating margin from our Permian crude assets with a $3.8 million decrease due to declines in crude oil prices and $3.8 million of that decrease due to the expiration of an MVC related to our South Texas assets in July 2019, and (ii) a $1.0 million decrease in gross operating margin from our Permian gas assets due to a $2.3 million decrease in gross operating margin related to our Midland Basin assets offset by a $1.3 million increase in gross operating margin related to our Delaware Basin assets.which was primarily driven by:

•~~North Texas Segment.~~ An increase in realized and unrealized derivative losses of $57.8 million and $14.7 million, respectively, due to significant commodity price impacts resulting from Winter Storm Uri.

•~~Gross operating~~A $3.0 million decrease to adjusted gross margin ~~in the North Texas segment decreased $6.9 million, which was~~associated with our Midland Basin crude assets primarily due to volume declines related to weather disruptions from Winter Storm Uri.

•A $0.8 million decrease in adjusted gross margin associated with our Delaware Basin gas assets primarily due to volume declines related to weather disruptions from Winter Storm Uri.

•These decreases were partially offset by a $38.1 million increase in adjusted gross margin due to significant favorable physical commodity price sales on our Midland Basin gas assets resulting from ~~limited new drilling~~Winter Storm Uri, which were more than offset by the derivative impact noted above, and a $1.1 million increase in ~~the region.~~adjusted gross margin due to volume growth in our Delaware Basin crude assets from system expansion.

•◦~~Oklahoma Segment.~~ ~~Gross operating margin~~Operating expenses in the ~~Oklahoma~~Permian segment decreased ~~$9.2 million. Gross operating margin contributed by our Oklahoma gas assets decreased $10.1~~$37.3 million ~~which was partially~~primarily due to lower ~~volumes from~~utility costs as a result of approximately $40.0 million of utility credits that we received because our ~~existing customers,~~electricity usage was below our contractual base load amounts during Winter Storm Uri, which entitled us to credits based on market rates for our unused electricity. These credits can be used to offset future utility payments. Operating expenses also decreased due to lower labor and ~~was~~benefits expense as a result of reductions in workforce in April 2020. These decreases were partially offset by ~~a $0.9~~increases in construction fees and services and materials and supplies expense.

◦Depreciation and amortization in the Permian segment increased $4.3 million ~~increase~~primarily due to new assets placed into service, including the expansion to our Riptide processing plant in ~~gross operating margin contributed by~~March 2020 and the completion of our ~~Oklahoma crude assets.~~Tiger processing plant in August 2020.

•Louisiana Segment.Gross ~~operating~~margin was $46.1 million for the three months ended March 31, 2021 compared to $37.5 million for the three months ended March 31, 2020, an increase of $8.6 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment ~~decreased $7.7~~increased $4.3 million, resulting ~~from (i) a $4.0~~from:

•A $21.7 million ~~decrease~~increase in adjusted gross ~~operating~~ margin ~~from~~associated with our Louisiana gas plants due to lower processing margins and volumes attributable to a less favorable processing environment, and (ii) a $3.7 million decrease in gross operating margin from our Louisiana gas transmission assets due to the expiration of certain firm transportation contracts and decreased volumes. While gross operating margin related to our ORV crude assets decreased $1.8 million, primarily due to lower volumes, this decrease was partially offset by an increase of $1.8 million in gross operating margin 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.~~

favorable market prices on NGL sales.

•~~Corporate Segment.~~ ~~Gross operating~~A $1.4 million increase in adjusted gross margin ~~in the Corporate segment increased $17.4 million,~~associated with our Louisiana gas assets, which was primarily due to increased gathering and transportation fees as a result of higher volumes transported in addition to increased storage and hub fees following our acquisition of the ~~changes~~Jefferson Island storage facility in ~~fair value of our commodity swaps between the periods as summarized below (in millions):~~December 2020.

Three Months Ended
March 31,
2020 2019
Realized swaps:
Crude swaps $ (0.6) $ 3.3
NGL swaps 5.2 1.9
Gas swaps 1.6 (1.4)
Realized gain on derivatives 6.2 3.8
Unrealized swaps:
Crude swaps 6.2 (0.4)
NGL swaps — (3.5)
Gas swaps 6.8 1.9
Change in fair value of derivatives 13.0 (2.0)
Gain on derivative activity $ 19.2 $ 1.8
•A $0.6 million decrease in unrealized derivative losses due to significant commodity price impacts resulting from Winter Storm Uri.

~~Certain gathering~~These increases were partially offset by a $15.0 million increase in realized derivative losses due to significant commodity price impacts resulting from Winter Storm Uri, and ~~processing agreements provide for quarterly or annual MVCs, including MVCs from Devon. Under these agreements,~~a $4.4 million decrease in adjusted gross margin associated with our ~~customers agree~~ORV crude assets, which was primarily due to ~~ship and/or process~~lower volumes.

◦Operating expenses in the Louisiana segment decreased $2.6 million primarily due to lower utility costs as a ~~minimum volume~~result of ~~commodity on our systems over an agreed time period. If~~Winter Storm Uri and lower labor and benefits expense as a ~~customer under such an agreement fails to meet its MVC for a specified period,~~result of reductions in workforce in April 2020. These decreases were partially offset by higher engineering fees and services associated with 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~~operation 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 MVCassets.

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~~contracts during periods~~◦Depreciation and amortization in the Louisiana segment decreased $1.7 million primarily due to the impairment of ~~shortfall when it is known that~~assets in the ~~customer cannot, or will not, make up the deficiency in subsequent periods.~~first quarter of 2020.

~~Revenue recorded~~•Oklahoma Segment. Gross margin was $4.8 million for the ~~shortfall between actual production volumes and the MVC is as follows (in millions):~~

Three Months Ended
March 31,
2020 2019
Permian Segment $ 2.0 $ 3.8
Oklahoma Segment 9.8 —
Total $ 11.8 $ 3.8

~~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 $100.7~~three months ended March 31, 2021 compared to $51.4 million for the three months ended March 31, 2020, ~~compared~~a decrease of $46.6 million primarily due to ~~$114.5~~the following:

◦Adjusted gross margin in the Oklahoma segment decreased $55.7 million, resulting from:

•A $32.2 million decrease in adjusted gross margin associated with our Oklahoma gas assets primarily due to lower volumes from our existing customers, including weather disruptions from Winter Storm Uri.

•A $9.5 million decrease in adjusted gross margin due to the expiration of the MVC provision of a gathering and processing contract at the end of 2020.

•An increase in realized and unrealized derivative losses of $6.8 million and $5.6 million, respectively, due to significant commodity price impacts resulting from Winter Storm Uri.

•A $1.6 million decrease in adjusted gross margin associated with our Oklahoma crude assets primarily due to lower volumes from our existing customers and partially as a result of weather disruptions from Winter Storm Uri.

◦Operating expenses in the Oklahoma segment decreased $3.2 million primarily due to reductions in compressor rentals related to the assets in this segment and labor and benefits expense as a result of reductions in workforce in April 2020. These decreases were partially offset by higher construction fees and services associated with work performed related to the assets in this segment.

◦Depreciation and amortization in the Oklahoma segment decreased $5.9 million primarily due to a change in the estimated useful lives of certain non-core assets in 2020.

•North Texas Segment. Gross margin was $48.2 million for the three months ended March 31, ~~2019, a decrease~~2021 compared to $37.0 million for the three months ended March 31, 2020, an increase of ~~$13.8 million, or 12.1%. The primary contributors to the total decrease by segment were as follows (in millions):~~

Three Months Ended
March 31, Change
2020 2019 $ %
Permian Segment $ 25.5 $ 27.8 $ (2.3) (8.3) %
North Texas Segment 20.5 25.7 (5.2) (20.2) %
Oklahoma Segment 22.9 25.4 (2.5) (9.8) %
Louisiana Segment 31.8 35.6 (3.8) (10.7) %
Total $ 100.7 $ 114.5 $ (13.8) (12.1) %

•~~Permian Segment.~~ ~~Operating expenses in the Permian segment decreased $2.3~~$11.2 million primarily due to ~~reductions in materials and supplies expenses.~~the following:

•◦Adjusted gross margin in the North Texas ~~Segment.~~ segment increased $1.4 million, which was primarily due to favorable market pricing resulting from Winter Storm Uri. The increase was partially offset by decreased revenues from volume declines and increased realized and unrealized derivative losses.

◦Operating expenses in the North Texas segment decreased ~~$5.2 million primarily due to reductions in materials and supplies expenses, construction fees and services, and vehicle rentals.~~

•~~Oklahoma Segment.~~ ~~Operating expenses in the Oklahoma segment decreased $2.5~~$1.3 million primarily due to reductions in compressor ~~operations~~rentals, reductions to labor and ~~maintenance,~~benefits expense as a result of reductions in workforce in April 2020, and reductions to utility costs. These decreases were partially offset by higher materials and supplies ~~expenses, construction fees~~expense related to the assets in this segment.

◦Depreciation and ~~services, and vehicle rentals.~~amortization in the North Texas segment decreased $8.5 million primarily due to a change in the estimated useful lives of certain non-core assets in 2020.

•~~Louisiana~~Corporate Segment.~~Operating expenses in~~ Gross margin was negative $2.0 million for each of the ~~Louisiana segment decreased $3.8 million primarily due to reductions in labor~~three months ended March 31, 2021 and ~~benefits costs, materials~~2020, respectively. Corporate gross margin consists of depreciation and ~~supplies expenses, construction fees and services, and vehicle rentals.~~amortization of corporate assets.

~~Operating expenses~~Impairments. We recognized no impairment expense for the three months ended March 31, 2021. For the three months ended March 31, 2020, ~~included $3.3 million of severance costs~~we recognized impairment expense related to ~~a reduction in workforce.~~goodwill and property and equipment, including cancelled projects. Impairment expense is composed of the following amounts (in millions):


	Three Months Ended March 31,
	2020
Goodwill impairment	$	184.6
Property and equipment impairment	168.0

Cancelled projects	0.4
Total impairments	$	353.0

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General and Administrative Expenses. General and administrative expenses were $26.0 million for the three months ended March 31, 2021 compared to $30.4 million for the three months ended March 31, 2020, ~~compared~~a decrease of $4.4 million. The decrease in general and administrative expenses was primarily due to ~~$51.4~~reduced labor costs and unit-based compensation costs, which decreased $5.0 million as a result of reductions in workforce in April 2020.

Interest Expense. Interest expense was $60.0 million for the three months ended March 31, ~~2019, a decrease of $21.0 million, or 40.9%. The primary contributors to the decrease were as follows:~~

•~~Transaction costs decreased $13.5 million, which was primarily due to higher transaction costs related to the Merger that were incurred during the first quarter of 2019.~~

•~~Unit-based compensation expense decreased $4.2 million, which was primarily due to larger awards and lower forfeitures during the first quarter of 2019 as~~2021 compared to ~~the first quarter of 2020.~~

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•~~Benefits and payroll taxes decreased $1.2 million, which was primarily due to a reduction in costs related to employee benefits.~~

~~General and administrative expenses for the three months ended March 31, 2020 included $2.6 million of severance costs related to a reduction in workforce.~~

~~Depreciation and Amortization.~~ ~~Depreciation and amortization was $162.8~~$55.6 million for the three months ended March 31, 2020, ~~compared to $152.1 million for the three months ended March 31, 2019,~~ an increase of $10.7 million, or 7.0%. This increase was primarily due to accelerated depreciation in the North Texas and Oklahoma segments on certain non-core assets based on changes in their estimated useful lives and new assets placed into service in key growth areas, including the Thunderbird Plant, the expansion$4.4 million. Interest expense consisted of the Lobo III cryogenic gas processing plant, the Cajun-Sibon NGL pipeline, Avenger, the Black Coyote crude oil gathering system, and well connections in Oklahoma. These increases were partially offset by retirements of certain non-core assets in the Louisiana segment during the first quarter of 2019.following (in millions):

~~Impairments.~~ For the three months ended March 31, 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. Additionally, we recorded a $0.4 million impairment related to certain cancelled projects. See “Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments.

During the three months ended March 31, 2020, we recognized a goodwill impairment of $184.6 million related to our Permian segment. During the three months ended March 31, 2019, we recognized a goodwill impairment of $186.5 million related to our Louisiana segment. See “Item 1. Financial Statements—Note 3” for additional information on our goodwill impairments.


	Three Months Ended March 31,
	2021		2020
ENLK and ENLC Senior Notes	$	50.3	$	44.0
Term Loan	1.4		6.4
AR Facility	1.2		—
Consolidated Credit Facility	1.3		4.1
Capitalized interest	(0.2)		(1.2)
Amortization of debt issue costs and net discounts (premiums)	1.2		1.0
Interest rate swap - realized	4.8		1.3

Total	$	60.0	$	55.6

Gain on Extinguishment of ~~Debt~~Debt. . We recognized a gain on extinguishment of debt of $5.3 million for the three months ended March 31, 2020 due to repurchases of the 2024, 2025, and 2026 Notes in open market transactions.

Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $6.3 million for the three months ended March 31, 2021 compared to income of $1.7 million for the three months ended March 31, 2020, a decrease of $8.0 million. The decrease was primarily attributable to a reduction of income of $7.5 million from our GCF investment, as a result of the GCF assets being temporarily idled beginning in January 2021, and a reduction of income of $0.5 million from our Cedar Cove JV.

Income Tax Benefit (Expense). Income tax expense was $1.4 million for the three months ended March 31, 2021 compared to an income tax benefit of $33.7 million for the three months ended March 31, 2020, which is primarily attributable to the decrease in loss between periods. See “Item 1. Financial Statements—Note 6” for additional information.

~~Interest Expense.~~ Interest expense was $55.6 million for the three months ended March 31, 2020 compared to $49.6 million for the three months ended March 31, 2019, an increase of $6.0 million, or 12.1%. Interest expense consisted of the following (in millions):

Three Months Ended
March 31,
2020 2019
ENLK and ENLC Senior Notes $ 44.0 $ 40.0
Term Loan 6.4 8.6
Consolidated Credit Facility 4.1 2.4
Capitalized interest (1.2) (2.0)
Amortization of debt issue costs and net discounts (premiums) 1.0 1.8
Other 1.3 (1.2)
Total $ 55.6 $ 49.6

~~Income Tax Expense.~~ Income tax benefit was $33.7 million for the three months ended March 31, 2020 compared to an income tax expense of $1.8 million for the three months ended March 31, 2019, a decrease in income tax expense of $35.5 million. The decrease in income tax expense was primarily attributable to lower income between periods. See “Item 1. Financial Statements—Note 7” for additional information.

~~Net Income (Loss) Attributable to Non-Controlling Interest.~~ Net income attributable to non-controlling interest was $26.4 million for the three months ended March 31, 2020 compared to net income of $41.5 million for the three months ended March 31, 2019, a decrease of $15.1 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 ENLK’s Series B Preferred Units, ENLK’s 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~~“Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, ~~2019, except as described below.~~

~~Property and Equipment~~

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 three months ended March 31, 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. Additionally, we recorded a $0.4 million impairment related to certain cancelled projects.

~~Goodwill Impairment~~

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

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activitieswas $225.8 million for the three months ended March 31, 2021 compared to $182.0 million for the three months ended March 31, ~~2020 compared to $264.0 million for the three months ended March 31, 2019.~~2020. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):


		Three Months Ended March 31,							Three Months Ended March 31,
		2020		2019			2021		2020
Operating cash flows before working capital	Operating cash flows before working capital	$	206.6	$	216.8	Operating cash flows before working capital	$	147.7	$	206.6
Changes in working capital	Changes in working capital	(24.6)		47.2		Changes in working capital	78.1		(24.6)

Operating cash flows before changes in working capital decreased ~~$10.2~~$58.9 million for the three months ended March 31, ~~2020~~2021 compared to the three months ended March 31, ~~2019.~~2020. The primary contributors to the decrease in operating cash flows were as follows:

•Gross ~~operating~~ margin, excluding depreciation and amortization, non-cash commodity swap activity, utility credits, and unit-based compensation, decreased ~~$35.8~~$57.8 million. For more information regarding the changes in gross margin for the three months ended March 31, 2021 compared to the three months ended March 31, 2020, see “Results of Operations.”

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•Distribution of earnings from unconsolidated affiliates decreased $1.6 million.

•Interest expense, excluding amortization of debt issue costs and net discounts (premium) of notes, increased ~~$6.8~~$4.2 million.

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

•General and administrative expenses excluding unit-based compensation decreased ~~$17.0~~$2.6 million primarily due to ~~higher transaction costs related to the Merger~~reductions in ~~January 2019. For more information, see “Results of Operations.”~~

•~~Operating expenses excluding unit-based compensation decreased $15.7 million primarily due to a reduction~~workforce in ~~operations. For more information, see “Results of Operations.”~~April 2020.

The changes in working capital for the three months ended March 31, ~~2020~~2021 compared to the three months ended March 31, ~~2019~~2020 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 $19.2 million for the three months ended March 31, 2021 compared to $115.5 million for the three months ended March 31, ~~2020, compared to $241.0 million for the three months ended March 31, 2019.~~2020. Investing cash flows are primarily related to capital expenditures. Capital expenditures decreased from ~~$241.5 million for the three months ended March 31, 2019 to~~ $112.0 million for the three months ended March 31, ~~2020.~~2020 to $23.5 million for the three months ended March 31, 2021. The decrease was primarily due to ~~reduced capital spending plans for 2020.~~the completion of major projects in 2020 and the timing of 2021 projects, which is more heavily weighted in the subsequent quarters of 2021.

Cash Flows from Financing Activities. Net cash used in financing activities was $173.4 million for the three months ended March 31, 2021 and net cash provided by financing activities was $114.2 million for the three months ended March 31, ~~2020 and net cash used in financing activities was $122.7 million for the three months ended March 31, 2019.~~2020. Our primary financing activities consisted of the following (in millions):

Three Months Ended
March 31,
2020 2019
Net repayments on the ENLC Credit Facility $ — $ (111.4)
Net borrowings 199.0 160.0
Contributions by non-controlling interests (1) 37.1 15.7
Distribution to members (93.3) (51.0)
Distributions to ENLK common units held by public unitholders (2) — (104.8)
Distributions to Series B Preferred Unitholders (3) (16.8) (16.5)
Distributions to joint venture partners (4) (7.9) (6.3)


	Three Months Ended March 31,
	2021		2020
Net repayments on the AR Facility (1)	$	(100.0)	$	—
Net borrowings on the Consolidated Credit Facility (1)	—		200.0
Net repurchases on ENLK’s senior unsecured notes (1)	—		(1.0)

Contributions by non-controlling interests (2)	0.9		37.1
Distribution to members	(47.1)		(93.3)
Distributions to Series B Preferred unitholders (3)	(16.9)		(16.8)

Distributions to joint venture partners (4)	(9.1)		(7.9)

____________________________

(1)See “Item 1. Financial Statements—Note 5” for more information regarding the AR Facility, the Consolidated Credit Facility, and the senior unsecured notes.

(2)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 8”7” for information on distributions to holders of the Series B 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~~2021 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately ~~$100~~$92 million to ~~$160~~$132 million, which is net of approximately ~~$10~~$3 million to ~~$40~~$5 million from our joint venture partners. Our primary capital projects for the remainder of ~~2020~~2021 include ~~the construction of the Tiger Plant in the Delaware Basin and~~ continued development of our existing ~~systems. See “Recent Developments” for further details.~~systems through well connects and other low-cost development projects. Additionally, we expect our remaining 2021 operating expenses related to the relocation of equipment and facilities previously associated with the Battle Ridge processing plant in Central Oklahoma to the Permian Basin to be approximately $17 million. These expenses are treated as an operating expense under GAAP and, therefore, are not included in our expected remaining 2021 capital expenditures.

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,~~2021, 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.

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Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of March 31, ~~2020.~~2021.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of March 31, ~~2020~~2021 is as follows (in millions):


		Payments Due by Period																											Payments Due by Period
		Total		Remainder 2020		2021		2022		2023		2024		Thereafter			Total		Remainder 2021		2022		2023		2024		2025		Thereafter
Long-term debt obligations		$	3,589.5	$	—	$	—	$	—	$	—	$	545.0	$	3,044.5
ENLC’s & ENLK’s senior unsecured notes																ENLC’s & ENLK’s senior unsecured notes	$	4,032.3	$	—	$	—	$	—	$	521.8	$	720.8	$	2,789.7
Term Loan(1)	Term Loan(1)	850.0		—		850.0		—		—		—		—		Term Loan(1)	350.0		350.0		—		—		—		—		—
Consolidated Credit Facility		550.0		—		—		—		—		550.0		—
AR Facility (2)																AR Facility (2)	150.0		—		—		150.0		—		—		—
Consolidated Credit Facility (3)																Consolidated Credit Facility (3)	—		—		—		—		—		—		—
Interest payable on fixed long-term debt obligations	Interest payable on fixed long-term debt obligations	2,499.7		163.6		175.6		175.6		175.6		163.6		1,645.7		Interest payable on fixed long-term debt obligations	2,511.3		176.3		201.2		201.2		189.7		163.3		1,579.6

Operating lease obligations	Operating lease obligations	133.9		16.3		17.0		12.2		10.2		9.5		68.7		Operating lease obligations	124.6		17.2		17.0		11.6		10.1		9.8		58.9
Purchase obligations	Purchase obligations	18.5		18.5		—		—		—		—		—		Purchase obligations	5.3		5.3		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements ~~(1)~~(4)	Pipeline and trucking capacity and deficiency agreements ~~(1)~~(4)	196.0		29.5		37.7		31.8		28.1		33.0		35.9		Pipeline and trucking capacity and deficiency agreements ~~(1)~~(4)	187.1		40.8		44.5		33.5		24.4		21.3		22.6
Inactive easement commitment ~~(2)~~(5)	Inactive easement commitment ~~(2)~~(5)	10.0		—		—		10.0		—		—		—		Inactive easement commitment ~~(2)~~(5)	10.0		—		10.0		—		—		—		—
Total contractual obligations	Total contractual obligations	$	7,847.6	$	227.9	$	1,080.3	$	229.6	$	213.9	$	1,301.1	$	4,794.8	Total contractual obligations	$	7,370.6	$	589.6	$	272.7	$	396.3	$	746.0	$	915.2	$	4,450.8

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(1)The Term Loan matures on December 10, 2021.

(2)The AR Facility is scheduled to terminate on October 20, 2023.

(3)The Consolidated Credit Facility will mature on January 25, 2024. As of March 31, 2021, there were no amounts outstanding under the Consolidated Credit Facility.

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

~~(2)~~(5)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~~Term Loan, the AR Facility, and the ~~Term Loan~~Consolidated Credit Facility are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the ~~Consolidated Credit~~Term Loan, the AR Facility, and the ~~Term Loan,~~Consolidated Credit Facility, which vary from time to time.

Our contractual cash obligations for the remainder of ~~2020~~2021 are expected to be funded from cash flows generated from our ~~operations.~~operations and the available capacity under the AR Facility, the Consolidated Credit Facility, or other debt sources.

Indebtedness

In ~~December 2018,~~October 2020, we entered into the ~~Consolidated Credit~~AR Facility, which ~~permits us to borrow~~is a three-year committed accounts receivable securitization facility originally in the amount of up to ~~$1.75 billion on a revolving credit basis~~$250.0 million. On February 26, 2021, the SPV entered into the First Amendment to the Receivables Financing Agreement, which amended the AR Facility to, among other things, increase the facility limit and ~~includes a $500.0~~lender commitments by $50.0 million ~~letter of credit subfacility.~~to $300.0 million. As of March 31, ~~2020,~~2021, the AR Facility had a borrowing base of $262.1 million and there was ~~$550.0~~$150.0 million in outstanding borrowings under the ~~Consolidated Credit Facility and $18.8 million in outstanding letters of credit.~~AR Facility.

In addition, as of March 31, ~~2020,~~2021, we have ~~$3.6~~$4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047 and ~~$850.0~~$350.0 million in outstanding principal on the Term Loan. There were no outstanding borrowings under the Consolidated Credit Facility and $27.5 million outstanding letters of credit as of March 31, 2021.

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Guarantees. The amounts outstanding on our senior unsecured notes, the Term Loan, and the Consolidated Credit Facility are guaranteed in full by our subsidiary ENLK, including 105% of any letters of credit outstanding on the Consolidated Credit Facility. ENLK’s guarantees of these amounts are full, irrevocable, unconditional, and absolute, and cover all payment obligations arising under the senior unsecured notes, the Term Loan, and the Consolidated Credit Facility. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness of ENLK.

ENLC’s material assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. Other than these equity interests, all of our material assets and operations are held by our non-guarantor operating subsidiaries. ENLK, directly and indirectly, owns all of these non-guarantor operating subsidiaries, which in some cases are joint ventures that are partially owned by a third party. As a result, the assets, liabilities, and results of operations of ENLK are not materially different than the corresponding amounts presented in our consolidated financial statements.

As of March 31, 2021, ENLC records, on a stand-alone basis, transactions that do not occur at ENLK related to taxation of ENLC, the elimination of intercompany borrowings, and impairment of goodwill that only existed at ENLC.

See “Item 1. Financial Statements—Note 6”5” for more information on our outstanding debt instruments.

Recent Accounting Pronouncements

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

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Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking 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, ~~operating efficiencies and other benefits of~~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 and Winter Storm Uri 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 ~~could adversely affect~~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 or prepayment event under our credit facility and certain of our other debt, (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~~increasing scrutiny and changing expectations from stakeholders with respect to our ~~major development projects,~~environment, social, and governance practices, (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 and the risk factors set forth ~~in Part II, “Item 1A. Risk Factors” of this report and~~ in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 may affect our performance and results of operations. Should one

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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

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industry associations and was vacated and remanded by a federal district court. The CFTC proposed new rules in ~~January~~February 2020 (withdrawing previously proposed ~~rules from November 2013 and December 2016)~~rules) 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~~adopted the ~~position limits~~proposed 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.~~with certain modifications, effective March 2021.

The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative 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 ~~89%~~82% of our adjusted gross ~~operating~~ margin for the three months ended March 31, ~~2020~~2021 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~~earn adjusted gross margin 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. We may also purchase and resell commodities in arrangements under which we are subject to commodity price fluctuations. Although historically this has not been a material component of our adjusted gross margin, Winter Storm Uri caused sudden and significant price and volume fluctuations that resulted in increased adjusted gross margin that is exposed to commodity price fluctuations. For more information on Winter Storm Uri and its impact on the Company, see the discussion at “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments Affecting Industry Conditions and Our Business—Winter Storm Uri” in this Report. For the three months ended March 31, 2021, approximately 17% of our adjusted gross margin was generated from purchase and resell arrangements under which we are subject to commodity price fluctuations. This amount was substantially offset by derivative losses.

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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 three months ended March 31, ~~2020,~~2021, less than 1% of our adjusted 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 three months ended March 31, ~~2020,~~2021, approximately 4%1% of our adjusted 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.

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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.

The following table sets forth certain information related to derivative instruments outstanding at March 31, ~~2020 mitigating~~2021. These derivative instruments mitigate 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)

April ~~2020~~2021 - ~~March~~December 2021

Ethane

~~2,017~~925 (MBbls)

$~~0.1365/gal~~0.2220/Gal

Index

~~0.2~~ (0.2)

April ~~2020~~2021 - ~~March~~December 2021

Propane

~~1,397~~2,665 (MBbls)

Index

$~~0.3162/gal~~0.8290/Gal

~~6.0~~ (12.8)

April ~~2020~~2021 - ~~March~~December 2021

Normal butane

~~458~~688 (MBbls)

Index

$~~0.3455/gal~~0.9335/Gal

~~2.2~~ (3.7)

April ~~2020~~2021 - December ~~2020~~2021

Natural gasoline

301,305 (MBbls)

Index

$~~0.4318/gal~~1.3211/Gal

~~0.2~~ (1.5)

April ~~2020~~2021 - January ~~2021~~2022

Natural gas

~~95,855 (MMBtu/~~40,326 (MMbtu/d)

Index

$~~1.2207/MMBtu~~2.6381/MMbtu

—0.4

April ~~2020~~2021 - ~~July 2020~~January 2022

Crude and condensate

~~4,275~~6,795 (MBbls)

Index

$~~23.92/~~57.94/Bbl

~~0.1~~ (0.7)

April ~~2020~~2021 - December 2022

Crude and condensate

~~10,970~~6,958 (MBbls)

$~~1.928/~~1.825/Bbl

Index (2)

8.5

~~12.7~~

~~21.4~~ (10.0)

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(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.

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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 March 31, ~~2020,~~2021, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value ~~asset~~liability of ~~$21.4~~$10.0 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 ~~$5.5~~$14.9 million in the net fair value of these contracts as of March 31, ~~2020.~~2021.

Interest Rate Risk

We are exposed to interest rate risk on the Consolidated Credit Facility, the Term Loan, and the ~~Term Loan.~~AR Facility. At March 31, ~~2020,~~2021, we had ~~$550.0~~$350.0 million and ~~$850.0~~$150.0 million in outstanding borrowings under the Term Loan and the AR Facility, respectively. At March 31, 2021, we had no outstanding borrowings under the Consolidated Credit ~~Facility and the Term Loan, respectively.~~ Facility.

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. In December 2020, in connection with the partial repayment of the Term Loan, we terminated $500.0 million of the $850.0 million interest rate swaps. See “Item 1. Financial Statements—Note ~~12”~~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 ~~$5.5~~$3.5 million and ~~$8.5~~$1.5 million for the ~~Consolidated Credit Facility~~Term Loan and the ~~Term Loan,~~AR Facility, respectively. This change in interest expense would be partially offset by ~~an $8.5~~a $3.5 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 2028 and 2029 as these are fixed-rate obligations. As of March 31, ~~2020,~~2021, the estimated fair value of the senior unsecured notes was approximately ~~$1,621.6~~$3,707.7 million, based on the market prices of ENLK’s and our publicly traded debt at March 31, ~~2020.~~2021. 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

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approximate ~~$79.3~~$230.3 million decrease in fair value of the senior unsecured notes at March 31, ~~2020.~~2021. See “Item 1. Financial Statements—Note 6”5” for more information on our outstanding indebtedness.

Item 4. Controls and Procedures

a.Evaluation of Disclosure Controls and Procedures

Management of the Managing Member is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for us. 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,~~the Managing Member, 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 (March 31, ~~2020)~~2021), 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~~our 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 March 31, ~~2020~~2021 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. InFor a discussion of certain litigation and similar proceedings, please refer to Note 15, “Commitments and Contingencies,” of the ~~opinion~~Notes to Consolidated Financial Statements contained in Part I of ~~management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect~~this Quarterly Report on ~~our financial position, results of operations, or cash flows.~~Form 10-Q, which is incorporated by reference herein.

Item 1A. Risk Factors

~~Except as set forth below, information~~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.~~

~~The ongoing coronavirus (COVID-19) outbreak could adversely affect our business, financial condition, and results of operations.~~

The ongoing coronavirus (COVID-19) outbreak, which the World Health Organization declared as a pandemic on March 11, 2020, has reached more than 200 countries and has continued to be a rapidly evolving situation. The pandemic has resulted in widespread adverse impacts on the global economy, the energy industry as a whole and on midstream companies, and on our employees, 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 significant reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for oil has dropped by nearly one-third since mid-February. The decline in demand has been met with a decline in the market price for these commodities, particularly for crude oil, and especially following the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire. On April 12, 2020, members of OPEC+ agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for oil and significantly higher costs for available storage. In the case of the oil markets, both the decline in demand and storage concerns have caused the price of oil to reach historic lows.

As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity and an uncertain timeline for recovery, oil and gas producers, including our customers, have sharply curtailed their current drilling and production activity as well as their plans for future drilling and production activity. As a result of these decreases in producer activity, our business and financial results have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets as a result of reduced production from the regions that supply our systems. In addition, available storage for crude oil is expected to be increasingly limited and costly for the foreseeable future, which would also have a negative impact on our customers’ ability to store crude oil during this period of reduced demand. If our producer customers are unable to store crude oil at reasonable prices, or the market prices our customers receive for their production stays at low levels for a prolonged period or declines even further, our customers could reduce their production levels or shut-in producing wells until storage is available and/or market prices recover. Consequently, our future business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders) could be materially and adversely affected.

There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how long they will continue to affect us.

We have modified certain business and workforce practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employees who can execute their work remotely, and encouraging employees to adhere to local and regional social distancing recommendations) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. Also, we have a limited number of highly skilled employees for some of our operations. If a large proportion of our employees in those critical positions were to contract COVID-19 at the same time, we would rely upon our business continuity plans in an effort to continue operations at our systems, pipelines, and facilities, but there is no certainty that such measures will be sufficient to mitigate the adverse impact to our operations that could result from shortages of highly skilled employees.

~~Table of Contents~~

Although we do not have plans to access the capital markets in 2020, to the extent that we need to seek external funding for our operations and COVID-19 adversely affects our ability to access the capital and other financial markets, as a result of credit rating downgrades or otherwise, we may need to consider alternative sources of funding for some of our operations and for working capital, which may increase our cost of, as well as adversely impact our access to, capital. These uncertain economic conditions may also result in the inability of our customers and other counterparties to make payments to us, on a timely basis or at all, which could adversely affect our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders and noteholders). A substantial deterioration in our business and/or a prolonged period of market dislocation could also affect our compliance with the financial covenants in our Consolidated Credit Facility, particularly the consolidated leverage ratio covenant. The leverage ratio covenant requires that we maintain a leverage ratio of no more than 5.0x at the end of any fiscal quarter. At March 31, 2020, our ratio was 4.6x. If we were unable to continue to meet any of the financial covenants, we would not be able to borrow funds under our Consolidated Credit Facility and we would not be able to use the Consolidated Credit Facility to refinance our $850 million Term Loan in 2021.

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders) at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus or its affects, the development of effective treatments, the duration of the outbreak, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume and whether the virus causes structural shifts in the global economy and the demand for oil and natural gas as a result of changes in the way people work, travel, and interact.2020.

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

During the three months ended March 31, ~~2020,~~2021, 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
January 1, 2020 to January 31, 2020 313,820 $ 6.04 — —
February 1, 2020 to February 29, 2020 473,438 4.54 — —
March 1, 2020 to March 31, 2020 6,135 0.93 — —
Total 793,393 $ 5.11 — —


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 (2)	Maximum Dollar Value of Units that May Yet Be Purchased under the Plans or Programs (in millions) (2)
January 1, 2021 to January 31, 2021	301,550	$	3.76	—	$	98.8
February 1, 2021 to February 28, 2021	—	—		—	$	98.8
March 1, 2021 to March 31, 2021	2,436	4.19		—	$	98.8
Total	303,986	$	3.76	—

____________________________

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

(2)During 2020, we announced a $100.0 million common unit repurchase program. As of March 31, 2021, we repurchased 383,614 common units for an aggregate price of $1.2 million, or an average of $3.00 per common unit. Future repurchases under the program may be made 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 repurchases will depend on market conditions and may be discontinued at any time.

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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 *†	—	First Amendment to the Receivables Financing Agreement, dated as of February 26, 2021, by and among EnLink Midstream Funding, LLC, ~~2014 Long-Term Incentive Plan (As Amended~~as borrower, EnLink Midstream Operating, LP, as initial servicer, and ~~Restated Effective~~PNC Bank, National Association, as administrative agent and as lender (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated February 26, 2021, filed with the Commission on March ~~31, 2020)~~1, 2021, file No. 001-36336).
22.1	—	Subsidiary Guarantors (incorporated by reference to Exhibit 22.1 to our Annual Report on Form 10-K dated December 31, 2020, filed with the Commission on February 17, 2021, file No. 001-36336).
31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	C~~Certification~~ertification 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 March 31, ~~2020,~~2021, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, (ii) Consolidated Statements of Operations for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended March 31, ~~2020~~2021 and ~~2019~~2020, (iv) Consolidated Statements of Cash Flows for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, 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/ ~~ERIC D. BATCHELDER~~J. PHILIPP ROSSBACH
		~~Eric D. Batchelder~~J. Philipp Rossbach
		~~Executive~~ Vice President and Chief ~~Financial~~Accounting Officer
		(Principal Accounting Officer)
May ~~8, 2020~~5, 2021

5350


Item	Item	Description	Page	Item	Description	Page

		PART I—FINANCIAL INFORMATION			PART I—FINANCIAL INFORMATION

1.	1.	Financial Statements	5	1.	Financial Statements	5

2.	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

3.	3.	Quantitative and Qualitative Disclosures About Market Risk	46	3.	Quantitative and Qualitative Disclosures About Market Risk	45

4.	4.	Controls and Procedures	49	4.	Controls and Procedures	47

		PART II—OTHER INFORMATION			PART II—OTHER INFORMATION

1.	1.	Legal Proceedings	50	1.	Legal Proceedings	48

1A.	1A.	Risk Factors	50	1A.	Risk Factors	48

2.	2.	Unregistered Sales of Equity Securities and Use of Proceeds	51	2.	Unregistered Sales of Equity Securities and Use of Proceeds	48

6.	6.	Exhibits	52	6.	Exhibits	49


	March 31, 2020			December 31, 2019







Operating leases:
Other assets, net	$	74.5		$	80.4
Other current liabilities	$	17.6		$	21.1
Other long-term liabilities	$	78.8		$	81.9

Other lease information

Weighted-average remaining lease term—Operating leases	11.0 years			10.6 years

Weighted-average discount rate—Operating leases	5.2		%	5.1		%


	Three Months Ended March 31,						Change
	2020		2019		$		%
Permian Segment	$	25.5	$	27.8	$	(2.3)	(8.3)	%
North Texas Segment	20.5		25.7		(5.2)		(20.2)	%
Oklahoma Segment	22.9		25.4		(2.5)		(9.8)	%
Louisiana Segment	31.8		35.6		(3.8)		(10.7)	%
Total	$	100.7	$	114.5	$	(13.8)	(12.1)	%