10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2022

OR

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

For the transition period from               to

Commission file number: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)

Delaware		46-4108528
(State of organization)		(I.R.S. Employer Identification No.)
1722 Routh St., Suite 1300
Dallas,	Texas	75201
(Address of principal executive offices)		(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

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

Title of Each Class	Trading Symbol	Name of Exchange on which Registered
Common Units Representing Limited Liability Company Interests	ENLC	The New York Stock Exchange

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

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

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

As of April 28, 2022, the Registrant had 483,011,794 common units outstanding.

TABLE OF CONTENTS

Item	Description	Page
	PART I—FINANCIAL INFORMATION
1.	Financial Statements	5
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
3.	Quantitative and Qualitative Disclosures About Market Risk	47
4.	Controls and Procedures	50
	PART II—OTHER INFORMATION
1.	Legal Proceedings	51
1A.	Risk Factors	51
2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
6.	Exhibits	52

2

DEFINITIONS

The following terms as defined are used in this document:

Defined Term	Definition
/d	Per day.
2014 Plan	ENLC’s 2014 Long-Term Incentive Plan.
Adjusted gross margin	Revenue less cost of sales, exclusive of operating expenses and depreciation and amortization. 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	An accounts receivable securitization facility of up to $350 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 and sustainability agent. The AR Facility is scheduled to terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms.
ASC	The Financial Accounting Standards Board Accounting Standards Codification.
ASC 718	ASC 718, Compensation—Stock Compensation.
ASC 820	ASC 820, Fair Value Measurements.
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.
Bbl	Barrel.
Bcf	Billion cubic feet.
Beginning TSR Price	The beginning total shareholder return (“TSR”) price, which is the closing unit price of ENLC on the grant date of the performance award agreement or the previous trading day if the grant date was not a trading day, is one of the assumptions used to calculate the grant-date fair value of performance award agreements.
CCS	Carbon capture, transportation, and sequestration.
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.
CO2	Carbon dioxide.
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. The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK.
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 processing plant located in the Delaware Basin in Texas.
ENLC	EnLink Midstream, LLC.
ENLC Class C Common Units	A class of non-economic ENLC common units issued immediately prior to the Merger equal to the number of Series B Preferred Units held immediately prior to the effective time of the Merger, in order to provide certain voting rights to holders of the Series B Preferred Units with respect to ENLC.
ENLK	EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
Exchange Act	The Securities Exchange Act of 1934, as amended.
GAAP	Generally accepted accounting principles in the United States of America.
Gal	Gallon.
GCF	Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF. The GCF assets have been temporarily idled to reduce operating expenses. We expect these assets to resume operations when there is a sustained need for additional fractionation capacity in Mont Belvieu.
General Partner	EnLink Midstream GP, LLC, the general partner of ENLK.

3

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.
ISDAs	International Swaps and Derivatives Association Agreements.
LIBOR	U.S. Dollar London Interbank Offered Rate.
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.
Midland Basin	A large sedimentary basin in West Texas.
MMbbls	Million barrels.
MMbtu	Million British thermal units.
MMcf	Million cubic feet.
MVC	Minimum volume commitment.
NGL	Natural gas liquid.
NGP	NGP Natural Resources XI, LP.
OPEC+	Organization of the Petroleum Exporting Countries and its broader partners.
Operating Partnership	EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
ORV	ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTC	Over-the-counter.
Permian Basin	A large sedimentary basin that includes the Midland and Delaware Basins primarily in West Texas and New Mexico.
POL contracts	Percentage-of-liquids contracts.
POP contracts	Percentage-of-proceeds contracts.
Series B Preferred Unit	ENLK’s Series B Cumulative Convertible Preferred Unit.
Series C Preferred Unit	ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit.
STACK	Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan	A term loan originally in the amount of $850.0 million 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 guaranteed. The Term Loan was paid at maturity.

4

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)

	March 31, 2022		December 31, 2021
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	68.7	$	26.2
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	70.4		94.9
Accrued revenue and other	857.9		693.3
Fair value of derivative assets	68.1		22.4
Other current assets	112.7		83.6
Total current assets	1,177.8		920.4
Property and equipment, net of accumulated depreciation of $4,450.6 and $4,332.0, respectively	6,321.8		6,388.3
Intangible assets, net of accumulated amortization of $827.9 and $795.1, respectively	1,016.9		1,049.7
Investment in unconsolidated affiliates	27.3		28.0
Fair value of derivative assets	0.1		0.2
Other assets, net	96.3		96.6
Total assets	$	8,640.2	$	8,483.2
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	131.7	$	139.6
Accrued gas, NGLs, condensate, and crude oil purchases (1)	740.0		521.5
Fair value of derivative liabilities	97.2		34.9
Other current liabilities	215.4		202.9
Total current liabilities	1,184.3		898.9
Long-term debt, net of unamortized issuance cost	4,315.0		4,363.7
Other long-term liabilities	94.0		93.9
Deferred tax liability, net	140.5		137.5
Fair value of derivative liabilities	0.6		2.2
Members’ equity:
Members’ equity (483,364,767 and 484,277,258 units issued and outstanding, respectively)	1,291.5		1,325.8
Accumulated other comprehensive loss	(1.3)		(1.4)
Non-controlling interest	1,615.6		1,662.6
Total members’ equity	2,905.8		2,987.0
Commitments and contingencies (Note 14)
Total liabilities and members’ equity	$	8,640.2	$	8,483.2

____________________________

(1)Includes related party accounts payable balances of $5.8 million and $1.6 million at March 31, 2022 and December 31, 2021, respectively.

See accompanying notes to consolidated financial statements.

5

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)

	Three Months Ended March 31,
	2022		2021
	(Unaudited)
Revenues:
Product sales	$	2,043.9	$	1,122.9
Midstream services	215.0		208.9
Loss on derivative activity	(31.2)		(83.4)
Total revenues	2,227.7		1,248.4
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	1,794.5		934.7
Operating expenses	120.9		56.3
Depreciation and amortization	152.9		151.0
Loss on disposition of assets	5.1		—
General and administrative	29.0		26.0
Total operating costs and expenses	2,102.4		1,168.0
Operating income	125.3		80.4
Other income (expense):
Interest expense, net of interest income	(55.1)		(60.0)
Loss from unconsolidated affiliate investments	(1.1)		(6.3)
Other income (expense)	0.1		(0.1)
Total other expense	(56.1)		(66.4)
Income before non-controlling interest and income taxes	69.2		14.0
Income tax expense	(3.2)		(1.4)
Net income	66.0		12.6
Net income attributable to non-controlling interest	30.8		25.3
Net income (loss) attributable to ENLC	$	35.2	$	(12.7)
Net income (loss) attributable to ENLC per unit:
Basic common unit	$	0.07	$	(0.03)
Diluted common unit	$	0.07	$	(0.03)

____________________________

(1)Includes related party cost of sales of $10.6 million and $3.2 million for the three months ended March 31, 2022 and 2021, respectively.

See accompanying notes to consolidated financial statements.

6

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

(In millions)

	Three Months Ended March 31,
	2022		2021
	(Unaudited)
Net income	$	66.0	$	12.6
Unrealized gain on designated cash flow hedge (1)	0.1		3.6
Comprehensive income	66.1		16.2
Comprehensive income attributable to non-controlling interest	30.8		25.3
Comprehensive income (loss) attributable to ENLC	$	35.3	$	(9.1)

____________________________

(1)Includes tax expense of $1.1 million for the three months ended March 31, 2021.

See accompanying notes to consolidated financial statements.

7

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

(In millions)

	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)
Balance, December 31, 2021	$	1,325.8	484.3	$	(1.4)	$	1,662.6	$	2,987.0
Conversion of restricted units for common units, net of units withheld for taxes	(4.2)		1.2	—		—		(4.2)
Unit-based compensation	8.1		—	—		—		8.1
Contributions from non-controlling interests	—		—	—		7.3		7.3
Distributions	(56.4)		—	—		(34.6)		(91.0)
Unrealized gain on designated cash flow hedge	—		—	0.1		—		0.1
Redemption of Series B Preferred Units	—		—	—		(50.5)		(50.5)
Common units repurchased	(17.0)		(2.1)	—		—		(17.0)
Net income	35.2		—	—		30.8		66.0
Balance, March 31, 2022	$	1,291.5	483.4	$	(1.3)	$	1,615.6	$	2,905.8

See accompanying notes to consolidated financial statements.

8

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity (Continued)

(In millions)

	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-Controlling Interest (Temporary Equity)
	$		Units	$		$		$		$
	(Unaudited)
Balance, December 31, 2020	$	1,508.8	489.4	$	(15.3)	$	1,719.5	$	3,213.0	$	—
Conversion of restricted units for common units, net of units withheld for taxes	(1.2)		0.7	—		—		(1.2)		—
Unit-based compensation	6.5		—	—		—		6.5		—
Contributions from non-controlling interests	—		—	—		0.9		0.9		—
Distributions	(47.1)		—	—		(25.8)		(72.9)		(0.2)
Unrealized gain on designated cash flow hedge (1)	—		—	3.6		—		3.6		—
Fair value adjustment related to redeemable non-controlling interest	(0.1)		—	—		—		(0.1)		0.2
Net income (loss)	(12.7)		—	—		25.3		12.6		—
Balance, March 31, 2021	$	1,454.2	490.1	$	(11.7)	$	1,719.9	$	3,162.4	$	—

____________________________

(1)Includes tax expense of $1.1 million.

See accompanying notes to consolidated financial statements.

9

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)

	Three Months Ended March 31,
	2022		2021
	(Unaudited)
Cash flows from operating activities:
Net income	$	66.0	$	12.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	152.9		151.0
Utility credits redeemed (earned)	5.6		(40.4)
Deferred income tax expense	3.0		1.3
Loss on disposition of assets	5.1		—
Non-cash unit-based compensation	6.6		6.5
Non-cash loss on derivatives recognized in net income	17.3		7.8
Amortization of debt issuance costs and net discount of senior unsecured notes	1.3		1.2
Loss from unconsolidated affiliate investments	1.1		6.3
Other operating activities	(1.1)		1.4
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(139.9)		(18.7)
Natural gas and NGLs inventory, prepaid expenses, and other	(32.8)		1.2
Accounts payable, accrued product purchases, and other accrued liabilities	222.6		95.6
Net cash provided by operating activities	307.7		225.8
Cash flows from investing activities:
Additions to property and equipment	(60.2)		(23.5)
Other investing activities	1.0		4.3
Net cash used in investing activities	(59.2)		(19.2)
Cash flows from financing activities:
Proceeds from borrowings	500.0		200.0
Repayments on borrowings	(550.0)		(300.0)
Distributions to members	(56.4)		(47.1)
Distributions to non-controlling interests	(34.6)		(26.0)
Redemption of Series B Preferred Units	(50.5)		—
Contributions by non-controlling interests	7.3		0.9
Common unit repurchases	(17.0)		—
Other financing activities	(4.8)		(1.2)
Net cash used in financing activities	(206.0)		(173.4)
Net increase in cash and cash equivalents	42.5		33.2
Cash and cash equivalents, beginning of period	26.2		39.6
Cash and cash equivalents, end of period	$	68.7	$	72.8
Supplemental disclosures of cash flow information:
Cash paid for interest	$	29.4	$	17.2
Non-cash investing activities:
Non-cash accrual of property and equipment	$	(0.2)	$	(2.7)
Right-of-use assets obtained in exchange for operating lease liabilities	$	8.5	$	10.2

See accompanying notes to consolidated financial statements.

10

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

March 31, 2022

(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, 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 ENLK’s common units and also owns all of 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 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 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.

11

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.

(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, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.

b.Revenue Recognition

The following table summarizes the contractually committed fees (in millions) 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. 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. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed Fees	Commitments
2022 (remaining)	$	110.3
2023	132.0
2024	112.0
2025	65.1
2026	57.9
Thereafter	289.7
Total	$	767.0

(3) Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years.

12

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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, 2022
Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7
Amortization expense	—		(32.8)		(32.8)
Customer relationships, end of period	$	1,844.8	$	(827.9)	$	1,016.9

Amortization expense was $32.8 million and $30.9 million for the three months ended March 31, 2022 and 2021, respectively.

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

2022 (remaining)	$	95.6
2023	127.6
2024	127.6
2025	110.2
2026	106.3
Thereafter	449.6
Total	$	1,016.9

(4) Related Party Transactions

(a)    Transactions with Cedar Cove JV

For the three months ended March 31, 2022 and 2021, we recorded cost of sales of $10.6 million and $3.2 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $5.8 million and $1.6 million at March 31, 2022 and December 31, 2021, respectively.

(b)    Transactions with GIP

General and Administrative Expenses. 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 not record any expenses related to transactions with GIP for the three months ended March 31, 2022.

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders. See “Note 8—Members’ Equity” for additional information on the activity relating to the GIP repurchase agreement.

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.

13

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(5) Long-Term Debt

As of March 31, 2022 and December 31, 2021, long-term debt consisted of the following (in millions):

	March 31, 2022						December 31, 2021
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Consolidated Credit Facility due 2024 (1)	$	—	$	—	$	—	$	15.0	$	—	$	15.0
AR Facility due 2024 (2)	315.0		—		315.0		350.0		—		350.0
ENLK’s 4.40% Senior unsecured notes due 2024	521.8		0.6		522.4		521.8		0.7		522.5
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.4)		720.4
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.3)		490.7
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.4)		444.6		450.0		(5.5)		444.5
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,347.3	$	(5.8)	4,341.5		$	4,397.3	$	(5.8)	4,391.5
Debt issuance cost (3)					(26.5)						(27.8)
Long-term debt, net of unamortized issuance cost					$	4,315.0					$	4,363.7

____________________________

(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2021.

(2)Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.5% and 1.2% at March 31, 2022 and December 31, 2021, respectively.

(3)Net of accumulated amortization of $19.7 million and $18.4 million at March 31, 2022 and December 31, 2021, 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. There were no outstanding borrowings under the Consolidated Credit Facility and $44.3 million outstanding letters of credit as of March 31, 2022.

At March 31, 2022, 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.

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. We are the primary beneficiary of the SPV and we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $882.6 million. As of March 31, 2022, the AR Facility had a borrowing base of $350.0 million and there were $315.0 million in outstanding borrowings under the AR Facility.

At March 31, 2022, 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.

14

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(6) Income Taxes

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

	Three Months Ended March 31,
	2022		2021
Current income tax expense	$	(0.2)	$	(0.1)
Deferred income tax expense	(3.0)		(1.3)
Income tax expense	$	(3.2)	$	(1.4)

The following schedule reconciles income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions):

	Three Months Ended March 31,
	2022		2021
Expected income tax benefit (expense) based on federal statutory rate	$	(8.1)	$	2.4
State income tax benefit (expense), net of federal benefit	(1.1)		0.2
Unit-based compensation (1)	(2.0)		(2.5)
Change in valuation allowance	7.1		(1.2)
Other	0.9		(0.3)
Income tax expense	$	(3.2)	$	(1.4)

____________________________

(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 liabilities, net of deferred tax assets, are included in “Deferred tax liability, net” in the consolidated balance sheets. As of March 31, 2022, we had $140.5 million of deferred tax liabilities, net of $484.8 million of deferred tax assets, which included a $144.5 million valuation allowance. As of December 31, 2021, we had $137.5 million of deferred tax liabilities, net of $481.6 million of deferred tax assets, which included a $151.6 million valuation allowance.

A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. As of March 31, 2022, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

15

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of March 31, 2022 and December 31, 2021, there were 54,168,359 and 57,501,693 Series B Preferred Units issued and outstanding, respectively.

In January 2022, we redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022.

A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2022 and 2021 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)
2021
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed.

(2)In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 is payable May 13, 2022.

b.Series C Preferred Units

As of March 31, 2022 and December 31, 2021, 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, 2022 and 2021.

16

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(8) Members’ Equity

a.Common Unit Repurchase Program

In November 2020, the board of directors of the Managing Member authorized a common unit repurchase program for the repurchase of up to $100.0 million of outstanding ENLC common units and reauthorized such program in April 2021. The Board reauthorized ENLC’s common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million effective January 1, 2022. Repurchases under the common unit repurchase program will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time.

For the three months ended March 31, 2022, ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of $17.0 million, or an average of $8.12 per common unit. For the three months ended March 31, 2021, we did not repurchase any outstanding ENLC common units.

b.GIP Repurchase Agreement

On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of $6.0 million, or an average of $8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period.

c.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,
	2022		2021
Distributed earnings allocated to:
Common units (1)	$	54.4	$	45.9
Unvested restricted units (1)	1.1		1.1
Total distributed earnings	$	55.5	$	47.0
Undistributed loss allocated to:
Common units	$	(19.9)	$	(58.3)
Unvested restricted units	(0.4)		(1.4)
Total undistributed loss	$	(20.3)	$	(59.7)
Net income (loss) attributable to ENLC allocated to:
Common units	$	34.5	$	(12.4)
Unvested restricted units	0.7		(0.3)
Total net income (loss) attributable to ENLC	$	35.2	$	(12.7)
Net income (loss) attributable to ENLC per unit:
Basic	$	0.07	$	(0.03)
Diluted	$	0.07	$	(0.03)

____________________________

(1)Represents distribution activity consistent with the distribution activity table below.

17

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

	Three Months Ended March 31,
	2022	2021
Basic weighted average units outstanding:
Weighted average common units outstanding	484.0	490.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	484.0	490.0
Dilutive effect of non-vested restricted units (1)	6.6	—
Total weighted average diluted common units outstanding	490.6	490.0

____________________________

(1)All common unit equivalents were antidilutive for the three months ended March 31, 2021, since a net loss existed for that period.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented.

d.Distributions

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2022 and 2021, respectively, is provided below:

Declaration period	Distribution/unit		Date paid/payable
2022
Fourth Quarter of 2021	$	0.11250	February 11, 2022
First Quarter of 2022	$	0.11250	May 13, 2022
2021
Fourth Quarter of 2020	$	0.09375	February 12, 2021
First Quarter of 2021	$	0.09375	May 14, 2021

18

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(9) Employee Incentive Plans

a.Long-Term Incentive Plans

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

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

	Three Months Ended March 31,
	2022		2021
Cost of unit-based compensation charged to operating expense	$	1.6	$	1.7
Cost of unit-based compensation charged to general and administrative expense	5.0		4.8
Total unit-based compensation expense	$	6.6	$	6.5
Amount of related income tax benefit recognized in net income (1)	$	1.6	$	1.5

____________________________

(1)For the three months ended March 31, 2022 and 2021, the amount of related income tax benefit recognized in net income excluded $2.0 million and $2.5 million, respectively, of income tax expense related to book-to-tax differences recorded upon the 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, 2022 is provided below:

	Three Months Ended March 31, 2022
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	7,507,471		$	5.46
Granted (1)	1,761,711		8.87
Vested (1)(2)	(1,032,738)		10.35
Forfeited	(2,022)		3.71
Non-vested, end of period	8,234,422		$	5.58
Aggregate intrinsic value, end of period (in millions)	$	79.5

____________________________

(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included 278,866 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions):

	Three Months Ended March 31,
ENLC Restricted Incentive Units:	2022		2021
Aggregate intrinsic value of units vested	$	7.6	$	3.0
Fair value of units vested	$	10.7	$	10.2

19

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

As of March 31, 2022, there were $24.5 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted-average period of 2.0 years.

c.ENLC Performance Units

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

The following table presents a summary of the performance units:

	Three Months Ended March 31, 2022
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	3,574,827		$	6.40
Granted	598,286		11.45
Vested (1)	(708,361)		15.57
Non-vested, end of period	3,464,752		$	5.40
Aggregate intrinsic value, end of period (in millions)	$	33.4

____________________________

(1)Vested units included 273,357 units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions).

	Three Months Ended March 31,
ENLC Performance Units:	2022		2021
Aggregate intrinsic value of units vested	$	5.6	$	0.6
Fair value of units vested	$	11.0	$	4.4

As of March 31, 2022, there were $15.5 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 1.9 years.

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

ENLC Performance Units:	March 2022 (1)			January 2021
Grant-date fair value	$	11.90		$	4.70
Beginning TSR price	$	8.83		$	3.71
Risk-free interest rate	2.15		%	0.17		%
Volatility factor	75.00		%	71.00		%

____________________________

(1)Excludes ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

20

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(10) Derivatives

Interest Rate Swaps

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

	Three Months Ended March 31,
	2022		2021
Change in fair value of interest rate swaps	$	0.1	$	4.7
Tax expense	—		(1.1)
Unrealized gain on designated cash flow hedge	$	0.1	$	3.6

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):

	Three Months Ended March 31,
	2022		2021
Interest expense	$	0.1	$	4.8

We expect to recognize an additional $0.1 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

Commodity Swaps

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

	Three Months Ended March 31,
	2022		2021
Change in fair value of derivatives	$	(15.1)	$	(7.9)
Realized loss on derivatives	(16.1)		(75.5)
Loss on derivative activity	$	(31.2)	$	(83.4)

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

	March 31, 2022		December 31, 2021
Fair value of derivative assets—current	$	68.1	$	22.4
Fair value of derivative assets—long-term	0.1		0.2
Fair value of derivative liabilities—current	(97.2)		(34.9)
Fair value of derivative liabilities—long-term	(0.6)		(2.2)
Net fair value of commodity swaps	$	(29.6)	$	(14.5)

21

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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, 2022 (in millions). The remaining term of the contracts extend no later than July 2023.

		March 31, 2022
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gals	(181.4)	$	(29.7)
Natural gas (short contracts)	Swaps	MMbtu	(3.7)	(3.9)
Natural gas (long contracts)	Swaps	MMbtu	2.8	2.9
Crude and condensate (short contracts)	Swaps	MMbbls	(4.7)	(59.3)
Crude and condensate (long contracts)	Swaps	MMbbls	4.0	60.4
Total fair value of commodity swaps				$	(29.6)

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of $68.2 million as of March 31, 2022 would be reduced to $0.7 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

22

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(11) Fair Value Measurements

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

	Level 2
	March 31, 2022		December 31, 2021
Commodity swaps (1)	$	(29.6)	$	(14.5)

____________________________

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

Fair Value of Financial Instruments

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

	March 31, 2022				December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,315.0	$	4,154.6	$	4,363.7	$	4,520.0
Installment payable (2)	$	10.0	$	10.0	$	10.0	$	10.0
Contingent consideration (2)	$	6.9	$	6.9	$	6.9	$	6.9

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $26.5 million and $27.8 million as of March 31, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration paid for the acquisition of Amarillo Rattler, LLC included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.

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, 2022 and December 31, 2021 were based on Level 2 inputs from third-party market quotations.

23

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(12) Segment Information

We evaluate 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. 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;

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

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

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

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

24

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

We evaluate the performance of our operating segments based on segment 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		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2022
Natural gas sales	$	195.6	$	211.5	$	76.3	$	25.4	$	—	$	508.8
NGL sales	—		1,151.5		3.1		(0.1)		—		1,154.5
Crude oil and condensate sales	272.0		73.9		34.7		—		—		380.6
Product sales	467.6		1,436.9		114.1		25.3		—		2,043.9
NGL sales—related parties	399.8		36.9		208.1		146.9		(791.7)		—
Crude oil and condensate sales—related parties	—		—		0.3		3.0		(3.3)		—
Product sales—related parties	399.8		36.9		208.4		149.9		(795.0)		—
Gathering and transportation	13.6		16.3		42.7		38.8		—		111.4
Processing	7.8		0.5		25.4		27.6		—		61.3
NGL services	—		23.9		—		—		—		23.9
Crude services	4.3		9.4		3.7		0.2		—		17.6
Other services	0.2		0.4		0.1		0.1		—		0.8
Midstream services	25.9		50.5		71.9		66.7		—		215.0
Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	—		0.1		—		—		(0.1)		—
Revenue from contracts with customers	893.3		1,524.4		394.4		241.9		(795.1)		2,258.9
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(766.7)		(1,388.7)		(276.8)		(157.4)		795.1		(1,794.5)
Realized loss on derivatives	(2.4)		(6.6)		(3.7)		(3.4)		—		(16.1)
Change in fair value of derivatives	(5.9)		(5.6)		(7.1)		3.5		—		(15.1)
Adjusted gross margin	118.3		123.5		106.8		84.6		—		433.2
Operating expenses	(45.3)		(33.0)		(21.0)		(21.6)		—		(120.9)
Segment profit	73.0		90.5		85.8		63.0		—		312.3
Depreciation and amortization	(36.7)		(35.5)		(50.9)		(28.4)		(1.4)		(152.9)
Gain (loss) on disposition of assets	—		0.2		0.2		(5.5)		—		(5.1)
General and administrative	—		—		—		—		(29.0)		(29.0)
Interest expense, net of interest income	—		—		—		—		(55.1)		(55.1)
Loss from unconsolidated affiliate investments	—		—		—		—		(1.1)		(1.1)
Other income	—		—		—		—		0.1		0.1
Income (loss) before non-controlling interest and income taxes	$	36.3	$	55.2	$	35.1	$	29.1	$	(86.5)	$	69.2
Capital expenditures	$	34.2	$	5.7	$	15.4	$	3.1	$	1.6	$	60.0

____________________________

(1)Includes related party cost of sales of $10.6 million for the three months ended March 31, 2022.

25

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2021
Natural gas sales	$	125.0	$	121.2	$	35.9	$	51.0	$	—	$	333.1
NGL sales	—		626.0		0.6		1.2		—		627.8
Crude oil and condensate sales	107.3		41.1		13.6		—		—		162.0
Product sales	232.3		788.3		50.1		52.2		—		1,122.9
NGL sales—related parties	164.9		23.6		113.1		80.9		(382.5)		—
Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—
Product sales—related parties	164.9		23.6		113.1		82.4		(384.0)		—
Gathering and transportation	9.7		15.8		51.3		40.4		—		117.2
Processing	8.2		0.5		15.9		27.1		—		51.7
NGL services	—		22.0		—		0.1		—		22.1
Crude services	3.5		9.9		3.3		0.2		—		16.9
Other services	0.2		0.5		0.2		0.1		—		1.0
Midstream services	21.6		48.7		70.7		67.9		—		208.9
Crude services—related parties	—		—		0.1		—		(0.1)		—
Other services—related parties	—		2.3		—		—		(2.3)		—
Midstream services—related parties	—		2.3		0.1		—		(2.4)		—
Revenue from contracts with customers	418.8		862.9		234.0		202.5		(386.4)		1,331.8
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	(56.9)		(10.7)		(6.0)		(1.9)		—		(75.5)
Change in fair value of derivatives	(5.3)		(0.4)		(1.8)		(0.4)		—		(7.9)
Adjusted gross margin	31.0		111.4		75.2		96.1		—		313.7
Operating expenses	11.8		(29.2)		(19.7)		(19.2)		—		(56.3)
Segment profit	42.8		82.2		55.5		76.9		—		257.4
Depreciation and amortization	(33.5)		(36.1)		(50.7)		(28.7)		(2.0)		(151.0)
Gain (loss) on disposition of assets	0.1		(0.1)		—		—		—		—
General and administrative	—		—		—		—		(26.0)		(26.0)
Interest expense, net of interest income	—		—		—		—		(60.0)		(60.0)
Loss from unconsolidated affiliate investments	—		—		—		—		(6.3)		(6.3)
Other loss	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	$	9.4	$	46.0	$	4.8	$	48.2	$	(94.4)	$	14.0
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.

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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, 2022 and December 31, 2021 (in millions):

Segment Identifiable Assets:	March 31, 2022		December 31, 2021
Permian	$	2,500.2	$	2,358.6
Louisiana	2,442.9		2,428.6
Oklahoma	2,582.9		2,619.5
North Texas	866.8		896.8
Corporate (1)	247.4		179.7
Total identifiable assets	$	8,640.2	$	8,483.2

____________________________

(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.

(13) 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:	March 31, 2022		December 31, 2021
Natural gas and NGLs inventory	$	73.6	$	49.4
Prepaid expenses and other	39.1		34.2
Other current assets	$	112.7	$	83.6

Other current liabilities:	March 31, 2022		December 31, 2021
Accrued interest	$	71.5	$	47.2
Accrued wages and benefits, including taxes	9.6		33.1
Accrued ad valorem taxes	12.6		28.3
Capital expenditure accruals	22.2		23.2
Deferred revenue	24.1		3.7
Short-term lease liability	20.3		18.1
Installment payable (1)	10.0		10.0
Inactive easement commitment (2)	9.9		9.8
Operating expense accruals	11.7		9.6
Other	23.5		19.9
Other current liabilities	$	215.4	$	202.9

____________________________

(1)Consideration paid for the acquisition of Amarillo Rattler, LLC included an installment payable, which was paid on April 30, 2022.

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

(14) 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 encountered customer billing disputes related to the delivery of gas during the storm, including one that resulted in litigation. The litigation is between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC (“Koch”) in the 162nd District Court in Dallas County, Texas. The dispute centers on whether EnLink Gas was excused from delivering gas or performing under certain delivery or purchase obligations during Winter Storm Uri, given our declaration of force majeure during the storm. Koch has invoiced us approximately $53.9 million (after subtracting amounts owed to EnLink Gas) and does not recognize the declaration of force majeure. We believe the declaration of force majeure was valid and appropriate and we intend to vigorously defend against Koch’s claims.

Another of our subsidiaries, EnLink Energy GP, LLC, is also involved in litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currently pending in Harris County, Texas, in which multiple individual plaintiffs assert personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators,

27

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

transmission/distribution utility, retail electric provider, and natural gas defendants across over 150 filed cases. We believe the claims against our subsidiary lack merit and we intend to vigorously defend against such claims.

In addition, we are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations, or cash flows. We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.

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

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

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

Overview

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

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

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

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

Our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography.

We evaluate 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. 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;

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

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

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

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

We manage our consolidated operations by focusing on adjusted gross margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Adjusted gross margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 90% of our

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adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the three months ended March 31, 2022.

Our revenues and adjusted gross 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 individually represented greater than 10% of our consolidated revenues for the three months ended March 31, 2022 and 2021. The loss of these customers 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. No other customers represented greater than 10% of our consolidated revenues during the periods presented.

	Three Months Ended March 31,
	2022		2021
Dow Hydrocarbons and Resources LLC	13.9	%	14.5	%
Marathon Petroleum Corporation	16.1	%	14.8	%

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

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margins are higher during periods of high NGL prices relative to natural gas prices. 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. 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 margins are driven by throughput volume.

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

CCS Business

We are currently developing an integrated offering to bring CCS services to businesses along the Mississippi River corridor in Louisiana, one of the highest CO2 emitting regions in the United States. We believe our existing asset footprint, including our extensive network of natural gas pipelines in Louisiana, our operating expertise and our customer relationships, provide EnLink an advantage in building a CCS business.

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. Commodity markets have now fully recovered from the reduction in global demand and low market prices experienced in 2020 due to the COVID-19 pandemic. However, oil and natural gas prices continue to remain volatile. Oil and natural gas prices, rose during 2021 and have risen very rapidly in 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical risks, including Russia’s invasion of Ukraine. As of the date of this report, the market price for both oil and natural gas are at higher levels than either has traded in many years.

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 during this same period. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, 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 by the COVID-19 pandemic, which reduced demand for commodities. However, in response to the rise of oil and natural gas prices during 2021 and in 2022 to date, capital investments by United States oil and natural gas producers have begun to rise modestly, although global capital investments by oil and natural gas producers remain at relatively low levels compared to historical levels and producers continue to remain cautious.

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

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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 Basin, other basins, including those in which we operate in Oklahoma and North Texas, have experienced reduced investment and declines in volumes produced, although that situation has begun to change as producers now see more opportunity in both Oklahoma and North Texas, given higher oil and natural gas prices. 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.

Our Louisiana segment, while subject to commodity price trends, 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 throughout 2021 and through the first quarter of 2022, 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 for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Extreme Weather Events

From time to time our operations may be affected by extreme weather events such as ice storms and hurricanes. In February 2021, certain 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 our facilities and activities across our 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, our gathering and processing volumes were significantly reduced during this period, with peak volume declines ranging between 44% and 92%, depending on the region. We responded to the challenges presented by the storm by taking active steps to ensure the resiliency of our assets and the protection of the health and well-being of our employees. Our operations and gathering and processing volumes returned to normal levels by the end of the first quarter of 2021.

Because of the magnitude and unprecedented nature of Winter Storm Uri, we cannot predict the full impact that the storm 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 or litigation 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. Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. 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, and we continue to evaluate our response plans and business practices to meet any evolving impacts of COVID-19 and its variants. Since the inception of the pandemic, we have not experienced any significant COVID-19 related operational disruptions.

Although the global impacts of COVID-19 have reduced significantly since the beginning of year, there remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic conditions.

We cannot predict the full impact that the COVID-19 pandemic or any related volatility in oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to unitholders) due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the pandemic, including variants of the virus, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the emergence of any new variants of the virus against which vaccines are less effective, 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, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, and the timing and extent to which normal economic, social, and operating conditions fully resume.

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For additional discussion regarding risks associated with the COVID-19 pandemic, see “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 for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

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 an ongoing comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. On June 15, 2021, however, a judge in the U.S. District Court for the Western District of Louisiana issued a nationwide temporary injunction blocking the suspension. The Department of the Interior appealed the U.S. District Court’s ruling but resumed oil and gas leasing pending resolution of the appeal. In November 2021, the Department of the Interior completed its review and issued a report on the federal oil and gas leasing program. The Department of the Interior’s report recommends several changes to federal leasing practices, including changes to royalty payments, bidding, and bonding requirements. On April 15, 2022, the Department of the Interior announced it would make roughly 144,000 acres of federal land available for new drilling, a significant reduction from the footprint of land that had been under evaluation for leasing. The new leases would also require companies to pay royalties of 18.75% of the value of extracted oil and gas products, up from 12.5%. Furthermore, 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. Lastly, on June 30, 2021, President Biden signed into law a reinstatement of regulations put in place during the Obama administration regarding methane emissions. The Company had previously complied with these regulations during the Obama administration and does not expect the reinstatement to have a material effect on the Company or its operations. 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 natural gas, 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. Our operations in the Delaware Basin are expected to represent only approximately 6% of our total segment profit, net to EnLink, during 2022. 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, the regulations that might result from such initiatives, 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 our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Other Recent Developments

CCS—Talos Alliance. In February 2022, we signed a memorandum of understanding with Talos Energy Inc. (“Talos”) to provide a complete CCS offering for industrial-scale emitters in Louisiana, utilizing our midstream assets combined with Talos’ subsurface assets. Talos has secured approximately 26,000 acres in Louisiana, providing sequestration capacity of over 500 million metric tonnes.

Phantom Processing Plant. In November 2021, we began moving equipment and facilities associated with the Thunderbird processing plant in Central Oklahoma to the Midland Basin. This processing plant relocation is expected to increase the processing capacity of our Permian Basin processing facilities by approximately 200 MMcf/d. We expect to complete the relocation in the fourth quarter of 2022.

Common Unit Repurchase Program. Effective January 1, 2022, the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million. For the three

33

months ended March 31, 2022, ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of $17.0 million, or an average of $8.12 per common unit.

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders.

On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of $6.0 million, or an average of $8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period. For more information about our repurchase agreement with GIP, see Part II, “9B. Other Information” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Redemption of Series B Preferred Units. In January 2022, we redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. See “Item 1. Financial Statements—Note 7” for more information regarding distributions with respect to the Series B Preferred Units.

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Non-GAAP Financial Measures

To assist management in assessing our business, we use the following non-GAAP financial measures: adjusted gross margin; adjusted earnings before interest, taxes, and depreciation and amortization (“adjusted EBITDA”); and free cash flow after distributions.

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization. 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 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 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,
	2022		2021
Total revenues	$	2,227.7	$	1,248.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,794.5)		(934.7)
Operating expenses	(120.9)		(56.3)
Depreciation and amortization	(152.9)		(151.0)
Gross margin	159.4		106.4
Operating expenses	120.9		56.3
Depreciation and amortization	152.9		151.0
Adjusted gross margin	$	433.2	$	313.7

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Adjusted EBITDA

We define adjusted EBITDA as net 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 disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; costs associated with the relocation of processing facilities; accretion expense associated with asset retirement obligations; transaction costs; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is one of the primary metrics used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:

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

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

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

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

The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in 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 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 to adjusted EBITDA (in millions):

	Three Months Ended March 31,
	2022		2021
Net income	$	66.0	$	12.6
Interest expense, net of interest income	55.1		60.0
Depreciation and amortization	152.9		151.0
Loss from unconsolidated affiliate investments	1.1		6.3
Distributions from unconsolidated affiliate investments	0.2		3.6
Loss on disposition of assets	5.1		—
Unit-based compensation	6.6		6.5
Income tax expense	3.2		1.4
Unrealized loss on commodity swaps	15.1		7.9
Costs associated with the relocation of processing facilities (1)	11.3		7.6
Other (2)	0.3		(0.4)
Adjusted EBITDA before non-controlling interest	316.9		256.5
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(12.6)		(7.1)
Adjusted EBITDA, net to ENLC	$	304.3	$	249.4

____________________________

(1)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.

(2)Includes accretion expense associated with asset retirement 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 and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV.

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Free Cash Flow After Distributions

We define free cash flow after distributions as adjusted EBITDA, net to ENLC, plus (less) (growth and maintenance capital expenditures, excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated 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); (costs associated with the relocation of processing facilities); non-cash interest (income)/expense; (payments to terminate interest rate swaps); (current income taxes); and proceeds from the sale of equipment and land.

Free cash flow after distributions is the principal cash flow metric used by the Company. Free cash flow after distributions is one of the primary metrics used in our short-term incentive program for compensating employees. It is also used as a supplemental liquidity 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, pay back our indebtedness, make cash distributions, and make capital expenditures.

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.

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.

The GAAP measure most directly comparable to free cash flow after distributions is net cash provided by operating activities. Free cash flow after distributions 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 liquidity presented in accordance with GAAP. Free cash flow after distributions has important limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Free cash flow after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate this non-GAAP 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 free cash flow after distributions, to evaluate our overall liquidity.

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

	Three Months Ended March 31,
	2022		2021
Net cash provided by operating activities	$	307.7	$	225.8
Interest expense (1)	53.7		55.9
Utility credits (redeemed) earned (2)	(5.6)		40.4
Accruals for settled commodity swap transactions	(2.2)		0.1
Distributions from unconsolidated affiliate investment in excess of earnings	0.2		3.6
Costs associated with the relocation of processing facilities (3)	11.3		7.6
Other (4)	1.7		1.2
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	172.7		17.5
Accounts payable, accrued product purchases, and other accrued liabilities	(222.6)		(95.6)
Adjusted EBITDA before non-controlling interest	316.9		256.5
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(12.6)		(7.1)
Adjusted EBITDA, net to ENLC	304.3		249.4
Growth capital expenditures, net to ENLC (6)	(40.5)		(15.9)
Maintenance capital expenditures, net to ENLC (6)	(13.9)		(4.7)
Interest expense, net of interest income	(55.1)		(60.0)
Distributions declared on common units	(55.5)		(46.7)
ENLK preferred unit accrued cash distributions (7)	(23.5)		(23.0)
Costs associated with the relocation of processing facilities (3)	(11.3)		(7.6)
Other (8)	0.4		2.7
Free cash flow after distributions	$	104.9	$	94.2

____________________________

(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, 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. These utility credits are recorded as “Other current assets” or “Other assets, net” on our consolidated balance sheets depending on the timing of their expected usage, and amortized as we incur utility expenses.

(3)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.

(4)Includes current income tax expense and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(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 and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV.

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

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

(8)Includes current income tax expense, non-cash interest (income)/expense, and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business.

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Results of Operations

The tables below set forth certain financial and operating data for the periods indicated. We 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, as reflected in the tables below (in millions, except volumes):

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2022
Gross margin	$	36.3	$	55.0	$	34.9	$	34.6	$	(1.4)	$	159.4
Depreciation and amortization	36.7		35.5		50.9		28.4		1.4		152.9
Segment profit	73.0		90.5		85.8		63.0		—		312.3
Operating expenses	45.3		33.0		21.0		21.6		—		120.9
Adjusted gross margin	$	118.3	$	123.5	$	106.8	$	84.6	$	—	$	433.2
Three Months Ended March 31, 2021
Gross margin	$	9.3	$	46.1	$	4.8	$	48.2	$	(2.0)	$	106.4
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

	Three Months Ended March 31,
	2022	2021
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d)	1,347,100	925,600
Processing (MMbtu/d)	1,256,300	876,100
Crude Oil Handling (Bbls/d)	150,700	108,200
Louisiana Segment
Gathering and Transportation (MMbtu/d)	2,497,700	2,151,300
Crude Oil Handling (Bbls/d)	15,900	15,000
NGL Fractionation (Gals/d)	8,033,900	7,106,200
Brine Disposal (Bbls/d)	3,000	1,400
Oklahoma Segment
Gathering and Transportation (MMbtu/d)	1,000,700	937,300
Processing (MMbtu/d)	1,029,500	955,400
Crude Oil Handling (Bbls/d)	23,800	17,500
North Texas Segment
Gathering and Transportation (MMbtu/d)	1,364,000	1,356,900
Processing (MMbtu/d)	614,300	624,600

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

Gross Margin. Gross margin was $159.4 million for the three months ended March 31, 2022 compared to $106.4 million for the three months ended March 31, 2021, an increase of $53.0 million. The primary contributors to the increase were as follows:

•Permian Segment. Gross margin was $36.3 million for the three months ended March 31, 2022 compared to $9.3 million for the three months ended March 31, 2021, an increase of $27.0 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased $87.3 million, which was primarily driven by:

•A $71.5 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $20.1 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Permian gas assets increased margin by $51.4 million, which included $56.7 million from decreased realized losses, primarily due to realized losses from Winter Storm Uri in February 2021, and $5.3 million from increased unrealized losses.

•A $15.8 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $13.3 million, which was primarily due to higher volumes from existing customers and the timing of physical trades. Derivative activity associated with our Permian crude assets increased margin by $2.5 million, which included $2.2 million from increased realized losses and $4.7 million from increased unrealized gains.

◦Operating expenses in the Permian segment increased $57.1 million primarily due to $40.0 million of utility credits that we received because our electricity usage was below our contractual base load amounts during Winter Storm Uri in February 2021. Operating expenses also increased due to higher construction fees and services and increases in materials and supplies expense and compressor rentals due to higher volumes.

◦Depreciation and amortization in the Permian segment increased $3.2 million primarily due to new assets placed into service, including gathering and processing assets associated with the acquisition of Amarillo Rattler, LLC in April 2021.

•Louisiana Segment. Gross margin was $55.0 million for the three months ended March 31, 2022 compared to $46.1 million for the three months ended March 31, 2021, an increase of $8.9 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment increased $12.1 million, resulting from:

•A $10.3 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $7.6 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by $2.7 million, which included $7.0 million from decreased realized losses and $4.3 million from increased unrealized losses.

•A $0.9 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $4.4 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana gas assets decreased margin by $3.5 million, which included $2.6 million from increased realized losses and $0.9 million from increased unrealized losses.

•A $0.9 million increase to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased $1.2 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our ORV crude assets decreased margin by $0.3 million from increased realized losses.

◦Operating expenses in the Louisiana segment increased $3.8 million primarily due to increases in utility costs and construction fees and services.

◦Depreciation and amortization in the Louisiana segment decreased $0.6 million primarily due to changes in estimated useful lives of certain non-core assets that were fully depreciated in the second quarter of 2021.

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•Oklahoma Segment. Gross margin was $34.9 million for the three months ended March 31, 2022 compared to $4.8 million for the three months ended March 31, 2021, an increase of $30.1 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment increased $31.6 million, resulting from:

•A $29.5 million increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $32.9 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma gas assets decreased margin by $3.4 million, which included $2.3 million from decreased realized losses and $5.7 million from increased unrealized losses.

•A $2.1 million increase to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, increased $1.7 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma crude assets increased margin by $0.4 million from decreased unrealized losses.

◦Operating expenses in the Oklahoma segment increased $1.3 million primarily due to increases in materials and supplies expense and construction fees and services. These increases were partially offset by a decrease in operation and maintenance costs and ad valorem taxes.

◦Depreciation and amortization in the Oklahoma segment increased $0.2 million due to additional assets placed in service, partially offset by the transfer of equipment to the Phantom and Warhorse processing facilities.

•North Texas Segment. Gross margin was $34.6 million for the three months ended March 31, 2022 compared to $48.2 million for the three months ended March 31, 2021, a decrease of $13.6 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment decreased $11.5 million. Adjusted gross margin, excluding derivative activity, decreased $13.9 million, which was primarily due to favorable market pricing resulting from Winter Storm Uri in February 2021. Derivative activity associated with our North Texas segment increased margin by $2.4 million, which included $1.5 million from increased realized losses and $3.9 million from increased unrealized gains.

◦Operating expenses in the North Texas segment increased $2.4 million primarily due to increases in materials and supplies expense, sales and use taxes, and utility costs. These increases were partially offset by a decrease in operations and maintenance costs.

◦Depreciation and amortization in the North Texas segment decreased $0.3 million primarily due to assets reaching the end of their depreciable lives.

•Corporate Segment. Gross margin was negative $1.4 million for the three months ended March 31, 2022 compared to negative $2.0 million for the three months ended March 31, 2021. Corporate gross margin consists of depreciation and amortization of corporate assets.

General and Administrative Expenses. General and administrative expenses were $29.0 million for the three months ended March 31, 2022 compared to $26.0 million for the three months ended March 31, 2021, an increase of $3.0 million. The increase was primarily due to labor and benefits costs and consulting fees and services.

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Interest Expense. Interest expense was $55.1 million for the three months ended March 31, 2022 compared to $60.0 million for the three months ended March 31, 2021, a decrease of $4.9 million. Interest expense consisted of the following (in millions):

	Three Months Ended March 31,
	2022		2021
ENLK and ENLC Senior Notes	$	50.3	$	50.3
Term Loan	—		1.4
Consolidated Credit Facility	2.3		1.3
AR Facility	1.1		1.2
Capitalized interest	—		(0.2)
Amortization of debt issuance costs and net discount of senior unsecured notes	1.3		1.2
Interest rate swaps - realized	0.1		4.8
Total	$	55.1	$	60.0

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $1.1 million for the three months ended March 31, 2022 compared to a loss of $6.3 million for the three months ended March 31, 2021, a reduction in loss of $5.2 million. The reduction in loss was primarily attributable to a reduction in loss of $5.0 million from our GCF investment, as a result of the GCF assets being idled beginning in January 2021, and a reduction in loss of $0.2 million from our Cedar Cove JV.

Income Tax Expense. Income tax expense was $3.2 million for the three months ended March 31, 2022 compared to an income tax expense of $1.4 million for the three months ended March 31, 2021. The increase in income tax expense was primarily attributable to the increase in income between periods. See “Item 1. Financial Statements—Note 6” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $30.8 million for the three months ended March 31, 2022 compared to net income of $25.3 million for the three months ended March 31, 2021, an increase of $5.5 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV. The increase in income was primarily due to a $4.6 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV and a $1.0 million increase attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV. These increases were offset by $0.1 million reduction in income attributable to the Series B Preferred Units following the partial redemptions of the Series B Units in December 2021 and January 2022.

Critical Accounting Policies

Information regarding our critical accounting policies is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $307.7 million for the three months ended March 31, 2022 compared to $225.8 million for the three months ended March 31, 2021. Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions):

	Three Months Ended March 31,
	2022		2021
Operating cash flows before working capital	$	257.8	$	147.7
Changes in working capital	49.9		78.1

Operating cash flows before changes in working capital increased $110.1 million for the three months ended March 31, 2022 compared to the three months ended March 31, 2021. The primary contributor to the increase in operating cash flows was as follows:

•Gross margin, excluding depreciation and amortization, non-cash commodity swap activity, utility credits redeemed or earned, and unit-based compensation, increased $110.3 million. For more information regarding the changes in gross

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margin for the three months ended March 31, 2022 compared to the three months ended March 31, 2021, see “Results of Operations.”

The changes in working capital for the three months ended March 31, 2022 compared to the three months ended March 31, 2021 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 $59.2 million for the three months ended March 31, 2022 compared to $19.2 million for the three months ended March 31, 2021. Our primary investing activities consisted of the following (in millions):

	Three Months Ended March 31,
	2022		2021
Additions to property and equipment (1)	$	(60.2)	$	(23.5)

____________________________

(1)The increase in capital expenditures was due to expansion projects to accommodate increased volumes on our systems.

Cash Flows from Financing Activities. Net cash used in financing activities was $206.0 million for the three months ended March 31, 2022 compared to $173.4 million for the three months ended March 31, 2021. Our primary financing activities consisted of the following (in millions):

	Three Months Ended March 31,
	2022		2021
Net repayments on the AR Facility (1)	$	(35.0)	$	(100.0)
Net repayments on the Consolidated Credit Facility (1)	(15.0)		—
Contributions by non-controlling interests (2)	7.3		0.9
Distributions to members	(56.4)		(47.1)
Distributions to Series B Preferred Unitholders (3)	(18.6)		(16.9)
Redemption of Series B Preferred Units (3)	(50.5)		—
Distributions to joint venture partners (4)	(16.0)		(9.1)
Common unit repurchases (5)	(17.0)		—

____________________________

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

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

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

(4)Represents distributions to NGP for its ownership in the Delaware Basin JV and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV.

(5)See “Item 1. Financial Statements—Note 8” for more information regarding the ENLC common unit repurchase program.

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Capital Requirements

The following table summarizes our expected remaining capital requirements for 2022 (in millions):

Capital expenditures, net to ENLC (1)	$	245
Operating expenses associated with the relocation of processing facilities (2)	34
Total	$	279

____________________________

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

(2)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant in the Oklahoma segment to the Permian segment. We expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.

Our primary capital projects for 2022 include the relocation of the Phantom processing plant, CCS-related initiatives, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining 2022 capital requirements from operating cash flows.

It is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of March 31, 2022.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of March 31, 2022 is as follows (in millions):

	Payments Due by Period
	Total		Remainder 2022		2023		2024		2025		2026		Thereafter
ENLC’s & ENLK’s senior unsecured notes	$	4,032.3	$	—	$	—	$	521.8	$	720.8	$	491.0	$	2,298.7
Consolidated Credit Facility (1)	—		—		—		—		—		—		—
AR Facility (2)	315.0		—		—		315.0		—		—		—
Acquisition installment payable (3)	10.0		10.0		—		—		—		—		—
Acquisition contingent consideration (4)	6.9		—		—		2.3		2.4		2.2		—
Interest payable on fixed long-term debt obligations	2,308.9		175.2		201.2		189.7		163.3		148.3		1,431.2
Operating lease obligations	116.6		17.7		19.2		10.5		9.8		8.9		50.5
Purchase obligations	4.6		4.6		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (5)	297.8		38.1		55.7		44.2		39.4		30.9		89.5
Inactive easement commitment (6)	10.0		10.0		—		—		—		—		—
Total contractual obligations	$	7,102.1	$	255.6	$	276.1	$	1,083.5	$	935.7	$	681.3	$	3,869.9

____________________________

(1)The Consolidated Credit Facility will mature on January 25, 2024. As of March 31, 2022, there were no amounts outstanding under the Consolidated Credit Facility.

(2)The AR Facility will terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms.

(3)Amount related to the consideration of the Amarillo Rattler, LLC acquisition, which was paid on April 30, 2022.

(4)The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from these estimated fair values. See “Item 1. Financial Statements—Note 11” for additional information.

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

(6)Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.

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

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

Our contractual cash obligations for the remainder of 2022 are expected to be funded from cash flows generated from our operations and the available capacity under the Consolidated Credit Facility, the AR Facility, or other debt sources.

Indebtedness

As of March 31, 2022, the AR Facility had a borrowing base of $350.0 million and there were $315.0 million in outstanding borrowings under the AR Facility.

In addition, as of March 31, 2022, we have $4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. There were no outstanding borrowings under the Consolidated Credit Facility and $44.3 million outstanding letters of credit as of March 31, 2022.

Guarantees. The amounts outstanding on our senior unsecured notes 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 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 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 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, 2022, ENLC records, on a stand-alone basis, transactions that do not occur at ENLK, which are primarily related to the taxation of ENLC and the elimination of intercompany borrowings.

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

Inflation

Inflation in the United States has been relatively low in recent years. However, the annual U.S. inflation rate accelerated in 2021 and through the first quarter of 2022. It is widely expected that this trend will continue for the remainder of 2022. In addition, at its March 2022 meeting, the Federal Reserve announced that it would be increasing its target for the federal funds rate (the benchmark for most interest rates) for the first time since 2018. Although we do not expect inflation to have a material effect on our results, higher inflation may increase the cost to acquire or replace property and equipment and the cost of labor and supplies. To the extent permitted by competition, regulation, and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees. Additionally, certain of our revenue generating contracts contain clauses that increase our fees based on changes in inflation metrics.

Recent Accounting Pronouncements

We have reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2022 and have determined that none would have a material impact to our consolidated financial statements.

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

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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, future cost savings or operational, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic, Winter Storm Uri, and other weather related events 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 operations, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) on our business, financial condition, and results of operations, (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 our significant customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect our significant customers 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) increasing scrutiny and changing expectations from stakeholders with respect to our 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, the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022 may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off or result in such counterparties spinning 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

47

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 also subject to direct risks due to fluctuations in commodity prices. While approximately 90% of our adjusted gross margin for the three months ended March 31, 2022 was generated from arrangements with fee-based structures with minimal direct commodity price exposure, the remainder is subject to more direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently 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 or (2) arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities.

2.Processing margin contracts. Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the three months ended March 31, 2022, less than 1% of our adjusted gross 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, 2022, approximately 9% of our adjusted gross margin was generated from POL or POP contracts.

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

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

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We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of NGLs, natural gas, and crude and condensate. The following table presents the relevant pricing index for each commodity:

Commodity	Index
NGLs	Oil Price Information Service
Natural gas	Henry Hub Gas Daily
Crude and condensate	New York Mercantile Exchange

The following table sets forth certain information related to derivative instruments outstanding at March 31, 2022.

Period	Underlying	Notional Volume	We Pay	We Receive (1)	Net Fair Value Asset/(Liability) (In millions)
April 2022 - March 2023	Ethane	1,645 (MMbbls)	$0.4280/Gal	Index	$	(3.7)
April 2022 - March 2023	Propane	2,190 (MMbbls)	Index	$1.3296/Gal	(21.3)
April 2022 - March 2023	Normal butane	465 (MMbbls)	Index	$1.6025/Gal	(4.7)
April 2022 - April 2022	Natural gasoline	20 (MMbbls)	Index	$2.5327/Gal	—
April 2022 - October 2022	Natural gas	17,699 (MMbtu/d)	Index	$5.6299/MMbtu	(1.0)
April 2022 - July 2023	Crude and condensate	8,670 (MMbbls)	Index	$93.07/Bbl	1.1
					$	(29.6)

____________________________

(1)Weighted average.

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

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

As of March 31, 2022, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value liability of $29.6 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in a change of approximately $25.4 million in the net fair value of these contracts as of March 31, 2022. 

Interest Rate Risk

We are exposed to interest rate risk on the Consolidated Credit Facility and the AR Facility. At March 31, 2022, we had $315.0 million in outstanding borrowings under the AR Facility. At March 31, 2022, we had no outstanding borrowings under the Consolidated Credit Facility. A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $3.2 million for the AR Facility.

Amounts drawn on the Consolidated Credit Facility and the AR Facility currently bear interest at rates based on LIBOR, which is beginning to be phased out. Both the Consolidated Credit Facility and the AR Facility include mechanisms to amend the facilities to reflect the establishment of an alternative to LIBOR, and the AR Facility has been amended to include a specific replacement reference rate alternative. The replacement rate for the AR Facility could result in a higher interest rate than LIBOR. If no such contractual alternative is established for the Consolidated Credit Facility before the LIBOR phase out is complete, it would bear interest at the prime rate, which would be higher than LIBOR, until a contractual alternative is established.

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,

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2022, the estimated fair value of the senior unsecured notes was approximately $3,839.6 million, based on the market prices of ENLK’s and our publicly traded debt at March 31, 2022. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1.0% in interest rates. Such an increase in interest rates would result in an approximate $240.8 million decrease in fair value of the senior unsecured notes at March 31, 2022. See “Item 1. Financial Statements—Note 5” for more information on our outstanding indebtedness.

Beginning on December 15, 2022, distributions on ENLK's Series C Preferred Units will be based on a floating rate tied to LIBOR plus 4.11% rather than a fixed rate and, therefore, the amount paid by ENLK as a distribution will be more sensitive to changes in interest rates.

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 management, including the Chief Executive Officer and Chief Financial Officer of 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, 2022), 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 Exchange Act 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 our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding 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, 2022 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. For a discussion of certain litigation and similar proceedings, please refer to Note 14, “Commitments and Contingencies,” of the Notes to Consolidated Financial Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

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

During the three months ended March 31, 2022, 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 and we repurchased common units in open market transactions in connection with our common unit repurchase program.

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, 2022 to January 31, 2022	1,625,954	$	7.57	1,148,473	$	91.3
February 1, 2022 to February 28, 2022	350,084	8.04		346,816	$	88.5
March 1, 2022 to March 31, 2022	670,027	9.14		598,553	$	83.0
Total	2,646,065	$	8.03	2,093,842

____________________________

(1)The total number of units purchased shown in the table includes 552,223 units received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)Effective January 1, 2022, the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million. For the three months ended March 31, 2022, we repurchased a total of 2,093,842 common units for an aggregate cost of $17.0 million, or an average of $8.12 per common unit under such program. 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 Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time. On February 15, 2022, we and GIP entered into an agreement pursuant to which we will repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter will be calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP will be the average per unit price paid by us for the common units repurchased from public unitholders. On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of $6.0 million, or an average of $8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period. For more information about our repurchase agreement with GIP, see Part II, “9B. Other Information” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

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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	—	Unit Repurchase Agreement, dated as of February 15, 2022 between EnLink Midstream, LLC, GIP III Stetson I, L.P. and GIP III Stetson II, L.P. (incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the Commission on February 16, 2022, file No. 001-36336).
22.1	—	Subsidiary Guarantors (incorporated by reference to Exhibit 22.1 to our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the Commission on February 16, 2022, file No. 001-36336).
31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	Certification of the Principal Financial Officer.
32.1 *	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101 *	—	The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of March 31, 2022 and December 31, 2021, (ii) Consolidated Statements of Operations for the three months ended March 31, 2022 and 2021, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended March 31, 2022 and 2021, (iv) Consolidated Statements of Cash Flows for the three months ended March 31, 2022 and 2021, and (v) the Notes to Consolidated Financial Statements.
104 *	—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

____________________________

*    Filed herewith.

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SIGNATURES

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

	EnLink Midstream, LLC
	By:	EnLink Midstream Manager, LLC, its managing member
	By:	/s/ J. PHILIPP ROSSBACH
		J. Philipp Rossbach
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)
May 4, 2022

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EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Barry E. Davis, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 4, 2022	/s/ BARRY E. DAVIS
	Barry E. Davis
	Chairman and Chief Executive Officer
	(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Pablo G. Mercado, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 4, 2022	/s/ PABLO G. MERCADO
	Pablo G. Mercado
	Executive Vice President and Chief Financial Officer
	(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of EnLink Midstream, LLC (the “Registrant”) on Form 10-Q of the Registrant for the quarter ended March 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned, Barry E. Davis, Chief Executive Officer of EnLink Midstream Manager, LLC, and Pablo G. Mercado, Chief Financial Officer of EnLink Midstream Manager, LLC, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

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

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

Date: May 4, 2022	/s/ BARRY E. DAVIS
	Barry E. Davis
	Chief Executive Officer
Date: May 4, 2022	/s/ PABLO G. MERCADO
	Pablo G. Mercado
	Chief Financial Officer

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

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Cover Page - shares	3 Months Ended
	Mar. 31, 2022	Apr. 28, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
Document Transition Report	false
Entity File Number	001-36336
Entity Registrant Name	ENLINK MIDSTREAM, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-4108528
Entity Address, Address Line One	1722 Routh St., Suite 1300
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75201
City Area Code	214
Local Phone Number	953-9500
Title of 12(b) Security	Common Units Representing Limited Liability Company Interests
Trading Symbol	ENLC
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		483,011,794
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2022
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31

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Consolidated Balance Sheets - USD ($) $ in Millions		Mar. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents		$ 68.7	$ 26.2
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively		70.4	94.9
Accrued revenue and other		857.9	693.3
Fair value of derivative assets		68.1	22.4
Other current assets		112.7	83.6
Total current assets		1,177.8	920.4
Property and equipment, net of accumulated depreciation of $4,450.6 and $4,332.0, respectively		6,321.8	6,388.3
Intangible assets, net of accumulated amortization of $827.9 and $795.1, respectively		1,016.9	1,049.7
Investment in unconsolidated affiliates		27.3	28.0
Fair value of derivative assets		0.1	0.2
Other assets, net		96.3	96.6
Total assets		8,640.2	8,483.2
Current liabilities:
Accounts payable and drafts payable		131.7	139.6
Accrued gas, NGLs, condensate, and crude oil purchases	[1]	740.0	521.5
Fair value of derivative liabilities		97.2	34.9
Other current liabilities		215.4	202.9
Total current liabilities		1,184.3	898.9
Long-term debt, net of unamortized issuance cost		4,315.0	4,363.7
Other long-term liabilities		94.0	93.9
Deferred tax liability, net		140.5	137.5
Fair value of derivative liabilities		0.6	2.2
Members’ equity:
Members’ equity (483,364,767 and 484,277,258 units issued and outstanding, respectively)		1,291.5	1,325.8
Accumulated other comprehensive loss		(1.3)	(1.4)
Non-controlling interest		1,615.6	1,662.6
Total members’ equity		2,905.8	2,987.0
Commitments and contingencies (Note 14)
Total liabilities and members’ equity		$ 8,640.2	$ 8,483.2

[1] Includes related party accounts payable balances of $5.8 million and $1.6 million at March 31, 2022 and December 31, 2021, respectively.

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
ASSETS
Allowance for bad debt	$ 0.3	$ 0.3
Property and equipment, accumulated depreciation	4,450.6	4,332.0
Intangible assets, accumulated amortization	$ 827.9	$ 795.1
Members’ equity:
Common units issued (in shares)	483,364,767	484,277,258
Common units outstanding (in shares)	484,277,258	483,364,767
Accounts payable to related party	$ 5.8	$ 1.6

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Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021
Revenues:
Revenue from contracts with customers		$ 2,258.9	$ 1,331.8
Loss on derivative activity		(31.2)	(83.4)
Total revenues		2,227.7	1,248.4
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	1,794.5	934.7
Operating expenses		120.9	56.3
Depreciation and amortization		152.9	151.0
Loss on disposition of assets		5.1	0.0
General and administrative		29.0	26.0
Total operating costs and expenses		2,102.4	1,168.0
Operating income		125.3	80.4
Other income (expense):
Interest expense, net of interest income		(55.1)	(60.0)
Loss from unconsolidated affiliate investments		(1.1)	(6.3)
Other income (expense)		0.1	(0.1)
Total other expense		(56.1)	(66.4)
Income before non-controlling interest and income taxes		69.2	14.0
Income tax expense		(3.2)	(1.4)
Net income		66.0	12.6
Net income attributable to non-controlling interest		30.8	25.3
Net income (loss) attributable to ENLC		$ 35.2	$ (12.7)
Net income (loss) attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ 0.07	$ (0.03)
Diluted common unit (in dollars per share)		$ 0.07	$ (0.03)
Product sales
Revenues:
Revenue from contracts with customers		$ 2,043.9	$ 1,122.9
Midstream services
Revenues:
Revenue from contracts with customers		$ 215.0	$ 208.9

[1] Includes related party cost of sales of $10.6 million and $3.2 million for the three months ended March 31, 2022 and 2021, respectively.

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Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Income Statement [Abstract]
Related party cost of sales	$ 10.6	$ 3.2

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Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income		$ 66.0	$ 12.6
Unrealized gain on designated cash flow hedge	[1]	0.1	3.6	[2]
Comprehensive income		66.1	16.2
Comprehensive income attributable to non-controlling interest		30.8	25.3
Comprehensive income (loss) attributable to ENLC		$ 35.3	$ (9.1)

[1] Includes tax expense of $1.1 million for the three months ended March 31, 2021.

[2] Includes tax expense of $1.1 million.

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Consolidated Statements of Comprehensive Income (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($)
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ 1.1

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Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Common Units	Accumulated Other Comprehensive Loss	Non-Controlling Interest	Redeemable Non-Controlling Interest (Temporary Equity)
Member equity, beginning balance at Dec. 31, 2020		$ 3,213.0		$ 1,508.8	$ (15.3)	$ 1,719.5
Units outstanding, beginning balance (in shares) at Dec. 31, 2020				489,400,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(1.2)		$ (1.2)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				700,000
Unit-based compensation		6.5		$ 6.5
Contributions from non-controlling interests		0.9				0.9
Distributions		(72.9)		(47.1)		(25.8)	$ (0.2)
Unrealized gain on designated cash flow hedge	[2]	3.6	[1]		3.6
Fair value adjustment related to redeemable non-controlling interest		$ (0.1)		(0.1)			0.2
Common units repurchased (in shares)		0
Net income (loss)		$ 12.6		(12.7)		25.3
Member equity, end balance at Mar. 31, 2021		3,162.4		$ 1,454.2	(11.7)	1,719.9
Units outstanding, end balance (in shares) at Mar. 31, 2021				490,100,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2020							0.0
Increase (Decrease) in Temporary Equity
Distributions		(72.9)		$ (47.1)		(25.8)	(0.2)
Fair value adjustment related to redeemable non-controlling interest		(0.1)		(0.1)			0.2
Redeemable noncontrolling interest, ending balance at Mar. 31, 2021							$ 0.0
Member equity, beginning balance at Dec. 31, 2021		$ 2,987.0		$ 1,325.8	(1.4)	1,662.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2021		484,277,258		484,300,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		$ (4.2)		$ (4.2)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				1,200,000
Unit-based compensation		8.1		$ 8.1
Contributions from non-controlling interests		7.3				7.3
Distributions		(91.0)		(56.4)		(34.6)
Unrealized gain on designated cash flow hedge		0.1	[1]		0.1
Redemption of non-controlling interest		(50.5)				(50.5)
Common units repurchased		$ (17.0)		$ (17.0)
Common units repurchased (in shares)		(2,093,842)		(2,100,000)
Net income (loss)		$ 66.0		$ 35.2		30.8
Member equity, end balance at Mar. 31, 2022		$ 2,905.8		$ 1,291.5	$ (1.3)	1,615.6
Units outstanding, end balance (in shares) at Mar. 31, 2022		483,364,767		483,400,000
Increase (Decrease) in Temporary Equity
Distributions		$ (91.0)		$ (56.4)		$ (34.6)

[1] Includes tax expense of $1.1 million for the three months ended March 31, 2021.

[2] Includes tax expense of $1.1 million.

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Consolidated Statement of Changes in Members' Equity (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($)
Statement of Stockholders' Equity [Abstract]
Income tax (benefit) expense	$ 1.1

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Cash flows from operating activities:
Net income	$ 66.0	$ 12.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	152.9	151.0
Utility credits redeemed (earned)	5.6	(40.4)
Deferred income tax expense	3.0	1.3
Loss on disposition of assets	5.1	0.0
Non-cash unit-based compensation	6.6	6.5
Non-cash loss on derivatives recognized in net income	17.3	7.8
Amortization of debt issuance costs and net discount of senior unsecured notes	1.3	1.2
Loss from unconsolidated affiliate investments	1.1	6.3
Other operating activities	(1.1)	1.4
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(139.9)	(18.7)
Natural gas and NGLs inventory, prepaid expenses, and other	(32.8)	1.2
Accounts payable, accrued product purchases, and other accrued liabilities	222.6	95.6
Net cash provided by operating activities	307.7	225.8
Cash flows from investing activities:
Additions to property and equipment	(60.2)	(23.5)
Other investing activities	1.0	4.3
Net cash used in investing activities	(59.2)	(19.2)
Cash flows from financing activities:
Proceeds from borrowings	500.0	200.0
Repayments on borrowings	(550.0)	(300.0)
Distributions to members	(56.4)	(47.1)
Distributions to non-controlling interests	(34.6)	(26.0)
Redemption of Series B Preferred Units	(50.5)	0.0
Contributions by non-controlling interests	7.3	0.9
Common unit repurchases	(17.0)	0.0
Other financing activities	(4.8)	(1.2)
Net cash used in financing activities	(206.0)	(173.4)
Net increase in cash and cash equivalents	42.5	33.2
Cash and cash equivalents, beginning of period	26.2	39.6
Cash and cash equivalents, end of period	68.7	72.8
Supplemental disclosures of cash flow information:
Cash paid for interest	29.4	17.2
Non-cash investing activities:
Non-cash accrual of property and equipment	(0.2)	(2.7)
Right-of-use assets obtained in exchange for operating lease liabilities	$ 8.5	$ 10.2

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General

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

(1) General

In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, 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 ENLK’s common units and also owns all of 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 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 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.

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.

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Significant Accounting Policies

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Significant Accounting Policies

(2) Significant Accounting Policies

a.Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.

b.Revenue Recognition

The following table summarizes the contractually committed fees (in millions) 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. 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. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed Fees	Commitments
2022 (remaining)	$	110.3
2023	132.0
2024	112.0
2025	65.1
2026	57.9
Thereafter	289.7
Total	$	767.0

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Intangible Assets

3 Months Ended

Mar. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

(3) Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 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, 2022
Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7
Amortization expense	—		(32.8)		(32.8)
Customer relationships, end of period	$	1,844.8	$	(827.9)	$	1,016.9

Amortization expense was $32.8 million and $30.9 million for the three months ended March 31, 2022 and 2021, respectively.

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

2022 (remaining)	$	95.6
2023	127.6
2024	127.6
2025	110.2
2026	106.3
Thereafter	449.6
Total	$	1,016.9

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Related Party Transactions

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Related Party Transactions

(4) Related Party Transactions

(a)    Transactions with Cedar Cove JV

For the three months ended March 31, 2022 and 2021, we recorded cost of sales of $10.6 million and $3.2 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $5.8 million and $1.6 million at March 31, 2022 and December 31, 2021, respectively.

(b)    Transactions with GIP

General and Administrative Expenses. 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 not record any expenses related to transactions with GIP for the three months ended March 31, 2022.

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders. See “Note 8—Members’ Equity” for additional information on the activity relating to the GIP repurchase agreement.

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.

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Long-Term Debt

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Long-Term Debt

(5) Long-Term Debt

As of March 31, 2022 and December 31, 2021, long-term debt consisted of the following (in millions):

	March 31, 2022						December 31, 2021
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Consolidated Credit Facility due 2024 (1)	$	—	$	—	$	—	$	15.0	$	—	$	15.0
AR Facility due 2024 (2)	315.0		—		315.0		350.0		—		350.0
ENLK’s 4.40% Senior unsecured notes due 2024	521.8		0.6		522.4		521.8		0.7		522.5
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.4)		720.4
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.3)		490.7
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.4)		444.6		450.0		(5.5)		444.5
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,347.3	$	(5.8)	4,341.5		$	4,397.3	$	(5.8)	4,391.5
Debt issuance cost (3)					(26.5)						(27.8)
Long-term debt, net of unamortized issuance cost					$	4,315.0					$	4,363.7

____________________________

(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2021.

(2)Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.5% and 1.2% at March 31, 2022 and December 31, 2021, respectively.

(3)Net of accumulated amortization of $19.7 million and $18.4 million at March 31, 2022 and December 31, 2021, 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. There were no outstanding borrowings under the Consolidated Credit Facility and $44.3 million outstanding letters of credit as of March 31, 2022.

At March 31, 2022, 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.

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. We are the primary beneficiary of the SPV and we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $882.6 million. As of March 31, 2022, the AR Facility had a borrowing base of $350.0 million and there were $315.0 million in outstanding borrowings under the AR Facility.

At March 31, 2022, 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.

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Income Taxes

3 Months Ended

Mar. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes

(6) Income Taxes

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

	Three Months Ended March 31,
	2022		2021
Current income tax expense	$	(0.2)	$	(0.1)
Deferred income tax expense	(3.0)		(1.3)
Income tax expense	$	(3.2)	$	(1.4)

The following schedule reconciles income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions):

	Three Months Ended March 31,
	2022		2021
Expected income tax benefit (expense) based on federal statutory rate	$	(8.1)	$	2.4
State income tax benefit (expense), net of federal benefit	(1.1)		0.2
Unit-based compensation (1)	(2.0)		(2.5)
Change in valuation allowance	7.1		(1.2)
Other	0.9		(0.3)
Income tax expense	$	(3.2)	$	(1.4)

____________________________

(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 liabilities, net of deferred tax assets, are included in “Deferred tax liability, net” in the consolidated balance sheets. As of March 31, 2022, we had $140.5 million of deferred tax liabilities, net of $484.8 million of deferred tax assets, which included a $144.5 million valuation allowance. As of December 31, 2021, we had $137.5 million of deferred tax liabilities, net of $481.6 million of deferred tax assets, which included a $151.6 million valuation allowance.

A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. As of March 31, 2022, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

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Certain Provisions of the ENLK Partnership Agreement

3 Months Ended

Mar. 31, 2022

Partners' Capital [Abstract]

Certain Provisions of the ENLK Partnership Agreement

(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of March 31, 2022 and December 31, 2021, there were 54,168,359 and 57,501,693 Series B Preferred Units issued and outstanding, respectively.

In January 2022, we redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022.

A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2022 and 2021 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)
2021
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed.

(2)In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 is payable May 13, 2022.

b.Series C Preferred Units

As of March 31, 2022 and December 31, 2021, 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, 2022 and 2021.

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Members' Equity

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Members' Equity

(8) Members’ Equity

a.Common Unit Repurchase Program

In November 2020, the board of directors of the Managing Member authorized a common unit repurchase program for the repurchase of up to $100.0 million of outstanding ENLC common units and reauthorized such program in April 2021. The Board reauthorized ENLC’s common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million effective January 1, 2022. Repurchases under the common unit repurchase program will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time.

For the three months ended March 31, 2022, ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of $17.0 million, or an average of $8.12 per common unit. For the three months ended March 31, 2021, we did not repurchase any outstanding ENLC common units.

b.GIP Repurchase Agreement

On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of $6.0 million, or an average of $8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period.

c.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,
	2022		2021
Distributed earnings allocated to:
Common units (1)	$	54.4	$	45.9
Unvested restricted units (1)	1.1		1.1
Total distributed earnings	$	55.5	$	47.0
Undistributed loss allocated to:
Common units	$	(19.9)	$	(58.3)
Unvested restricted units	(0.4)		(1.4)
Total undistributed loss	$	(20.3)	$	(59.7)
Net income (loss) attributable to ENLC allocated to:
Common units	$	34.5	$	(12.4)
Unvested restricted units	0.7		(0.3)
Total net income (loss) attributable to ENLC	$	35.2	$	(12.7)
Net income (loss) attributable to ENLC per unit:
Basic	$	0.07	$	(0.03)
Diluted	$	0.07	$	(0.03)

____________________________

(1)Represents distribution activity consistent with the distribution activity table below.

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

	Three Months Ended March 31,
	2022	2021
Basic weighted average units outstanding:
Weighted average common units outstanding	484.0	490.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	484.0	490.0
Dilutive effect of non-vested restricted units (1)	6.6	—
Total weighted average diluted common units outstanding	490.6	490.0

____________________________

(1)All common unit equivalents were antidilutive for the three months ended March 31, 2021, since a net loss existed for that period.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented.

d.Distributions

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2022 and 2021, respectively, is provided below:

Declaration period	Distribution/unit		Date paid/payable
2022
Fourth Quarter of 2021	$	0.11250	February 11, 2022
First Quarter of 2022	$	0.11250	May 13, 2022
2021
Fourth Quarter of 2020	$	0.09375	February 12, 2021
First Quarter of 2021	$	0.09375	May 14, 2021

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Employee Incentive Plans

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Employee Incentive Plans

(9) Employee Incentive Plans

a.Long-Term Incentive Plans

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

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

	Three Months Ended March 31,
	2022		2021
Cost of unit-based compensation charged to operating expense	$	1.6	$	1.7
Cost of unit-based compensation charged to general and administrative expense	5.0		4.8
Total unit-based compensation expense	$	6.6	$	6.5
Amount of related income tax benefit recognized in net income (1)	$	1.6	$	1.5

____________________________

(1)For the three months ended March 31, 2022 and 2021, the amount of related income tax benefit recognized in net income excluded $2.0 million and $2.5 million, respectively, of income tax expense related to book-to-tax differences recorded upon the 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, 2022 is provided below:

	Three Months Ended March 31, 2022
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	7,507,471		$	5.46
Granted (1)	1,761,711		8.87
Vested (1)(2)	(1,032,738)		10.35
Forfeited	(2,022)		3.71
Non-vested, end of period	8,234,422		$	5.58
Aggregate intrinsic value, end of period (in millions)	$	79.5

____________________________

(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included 278,866 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions):

	Three Months Ended March 31,
ENLC Restricted Incentive Units:	2022		2021
Aggregate intrinsic value of units vested	$	7.6	$	3.0
Fair value of units vested	$	10.7	$	10.2

As of March 31, 2022, there were $24.5 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted-average period of 2.0 years.

c.ENLC Performance Units

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

The following table presents a summary of the performance units:

	Three Months Ended March 31, 2022
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	3,574,827		$	6.40
Granted	598,286		11.45
Vested (1)	(708,361)		15.57
Non-vested, end of period	3,464,752		$	5.40
Aggregate intrinsic value, end of period (in millions)	$	33.4

____________________________

(1)Vested units included 273,357 units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions).

	Three Months Ended March 31,
ENLC Performance Units:	2022		2021
Aggregate intrinsic value of units vested	$	5.6	$	0.6
Fair value of units vested	$	11.0	$	4.4

As of March 31, 2022, there were $15.5 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 1.9 years.

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

ENLC Performance Units:	March 2022 (1)			January 2021
Grant-date fair value	$	11.90		$	4.70
Beginning TSR price	$	8.83		$	3.71
Risk-free interest rate	2.15		%	0.17		%
Volatility factor	75.00		%	71.00		%

____________________________

(1)Excludes ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

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Derivatives

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(10) Derivatives

Interest Rate Swaps

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

	Three Months Ended March 31,
	2022		2021
Change in fair value of interest rate swaps	$	0.1	$	4.7
Tax expense	—		(1.1)
Unrealized gain on designated cash flow hedge	$	0.1	$	3.6

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):

	Three Months Ended March 31,
	2022		2021
Interest expense	$	0.1	$	4.8

We expect to recognize an additional $0.1 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

Commodity Swaps

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

	Three Months Ended March 31,
	2022		2021
Change in fair value of derivatives	$	(15.1)	$	(7.9)
Realized loss on derivatives	(16.1)		(75.5)
Loss on derivative activity	$	(31.2)	$	(83.4)

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

	March 31, 2022		December 31, 2021
Fair value of derivative assets—current	$	68.1	$	22.4
Fair value of derivative assets—long-term	0.1		0.2
Fair value of derivative liabilities—current	(97.2)		(34.9)
Fair value of derivative liabilities—long-term	(0.6)		(2.2)
Net fair value of commodity swaps	$	(29.6)	$	(14.5)

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, 2022 (in millions). The remaining term of the contracts extend no later than July 2023.

		March 31, 2022
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gals	(181.4)	$	(29.7)
Natural gas (short contracts)	Swaps	MMbtu	(3.7)	(3.9)
Natural gas (long contracts)	Swaps	MMbtu	2.8	2.9
Crude and condensate (short contracts)	Swaps	MMbbls	(4.7)	(59.3)
Crude and condensate (long contracts)	Swaps	MMbbls	4.0	60.4
Total fair value of commodity swaps				$	(29.6)

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of $68.2 million as of March 31, 2022 would be reduced to $0.7 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Measurements

(11) Fair Value Measurements

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

	Level 2
	March 31, 2022		December 31, 2021
Commodity swaps (1)	$	(29.6)	$	(14.5)

____________________________

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

Fair Value of Financial Instruments

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

	March 31, 2022				December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,315.0	$	4,154.6	$	4,363.7	$	4,520.0
Installment payable (2)	$	10.0	$	10.0	$	10.0	$	10.0
Contingent consideration (2)	$	6.9	$	6.9	$	6.9	$	6.9

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $26.5 million and $27.8 million as of March 31, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration paid for the acquisition of Amarillo Rattler, LLC included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.

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, 2022 and December 31, 2021 were based on Level 2 inputs from third-party market quotations.

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Segment Information

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Segment Information

(12) Segment Information

We evaluate 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. 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;

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

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

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

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

We evaluate the performance of our operating segments based on segment 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		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2022
Natural gas sales	$	195.6	$	211.5	$	76.3	$	25.4	$	—	$	508.8
NGL sales	—		1,151.5		3.1		(0.1)		—		1,154.5
Crude oil and condensate sales	272.0		73.9		34.7		—		—		380.6
Product sales	467.6		1,436.9		114.1		25.3		—		2,043.9
NGL sales—related parties	399.8		36.9		208.1		146.9		(791.7)		—
Crude oil and condensate sales—related parties	—		—		0.3		3.0		(3.3)		—
Product sales—related parties	399.8		36.9		208.4		149.9		(795.0)		—
Gathering and transportation	13.6		16.3		42.7		38.8		—		111.4
Processing	7.8		0.5		25.4		27.6		—		61.3
NGL services	—		23.9		—		—		—		23.9
Crude services	4.3		9.4		3.7		0.2		—		17.6
Other services	0.2		0.4		0.1		0.1		—		0.8
Midstream services	25.9		50.5		71.9		66.7		—		215.0
Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	—		0.1		—		—		(0.1)		—
Revenue from contracts with customers	893.3		1,524.4		394.4		241.9		(795.1)		2,258.9
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(766.7)		(1,388.7)		(276.8)		(157.4)		795.1		(1,794.5)
Realized loss on derivatives	(2.4)		(6.6)		(3.7)		(3.4)		—		(16.1)
Change in fair value of derivatives	(5.9)		(5.6)		(7.1)		3.5		—		(15.1)
Adjusted gross margin	118.3		123.5		106.8		84.6		—		433.2
Operating expenses	(45.3)		(33.0)		(21.0)		(21.6)		—		(120.9)
Segment profit	73.0		90.5		85.8		63.0		—		312.3
Depreciation and amortization	(36.7)		(35.5)		(50.9)		(28.4)		(1.4)		(152.9)
Gain (loss) on disposition of assets	—		0.2		0.2		(5.5)		—		(5.1)
General and administrative	—		—		—		—		(29.0)		(29.0)
Interest expense, net of interest income	—		—		—		—		(55.1)		(55.1)
Loss from unconsolidated affiliate investments	—		—		—		—		(1.1)		(1.1)
Other income	—		—		—		—		0.1		0.1
Income (loss) before non-controlling interest and income taxes	$	36.3	$	55.2	$	35.1	$	29.1	$	(86.5)	$	69.2
Capital expenditures	$	34.2	$	5.7	$	15.4	$	3.1	$	1.6	$	60.0

____________________________

(1)Includes related party cost of sales of $10.6 million for the three months ended March 31, 2022.

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2021
Natural gas sales	$	125.0	$	121.2	$	35.9	$	51.0	$	—	$	333.1
NGL sales	—		626.0		0.6		1.2		—		627.8
Crude oil and condensate sales	107.3		41.1		13.6		—		—		162.0
Product sales	232.3		788.3		50.1		52.2		—		1,122.9
NGL sales—related parties	164.9		23.6		113.1		80.9		(382.5)		—
Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—
Product sales—related parties	164.9		23.6		113.1		82.4		(384.0)		—
Gathering and transportation	9.7		15.8		51.3		40.4		—		117.2
Processing	8.2		0.5		15.9		27.1		—		51.7
NGL services	—		22.0		—		0.1		—		22.1
Crude services	3.5		9.9		3.3		0.2		—		16.9
Other services	0.2		0.5		0.2		0.1		—		1.0
Midstream services	21.6		48.7		70.7		67.9		—		208.9
Crude services—related parties	—		—		0.1		—		(0.1)		—
Other services—related parties	—		2.3		—		—		(2.3)		—
Midstream services—related parties	—		2.3		0.1		—		(2.4)		—
Revenue from contracts with customers	418.8		862.9		234.0		202.5		(386.4)		1,331.8
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	(56.9)		(10.7)		(6.0)		(1.9)		—		(75.5)
Change in fair value of derivatives	(5.3)		(0.4)		(1.8)		(0.4)		—		(7.9)
Adjusted gross margin	31.0		111.4		75.2		96.1		—		313.7
Operating expenses	11.8		(29.2)		(19.7)		(19.2)		—		(56.3)
Segment profit	42.8		82.2		55.5		76.9		—		257.4
Depreciation and amortization	(33.5)		(36.1)		(50.7)		(28.7)		(2.0)		(151.0)
Gain (loss) on disposition of assets	0.1		(0.1)		—		—		—		—
General and administrative	—		—		—		—		(26.0)		(26.0)
Interest expense, net of interest income	—		—		—		—		(60.0)		(60.0)
Loss from unconsolidated affiliate investments	—		—		—		—		(6.3)		(6.3)
Other loss	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	$	9.4	$	46.0	$	4.8	$	48.2	$	(94.4)	$	14.0
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.

The table below represents information about segment assets as of March 31, 2022 and December 31, 2021 (in millions):

Segment Identifiable Assets:	March 31, 2022		December 31, 2021
Permian	$	2,500.2	$	2,358.6
Louisiana	2,442.9		2,428.6
Oklahoma	2,582.9		2,619.5
North Texas	866.8		896.8
Corporate (1)	247.4		179.7
Total identifiable assets	$	8,640.2	$	8,483.2

____________________________(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.

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Other Information

3 Months Ended

Mar. 31, 2022

Other Liabilities Disclosure [Abstract]

Other Information

(13) 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:	March 31, 2022		December 31, 2021
Natural gas and NGLs inventory	$	73.6	$	49.4
Prepaid expenses and other	39.1		34.2
Other current assets	$	112.7	$	83.6

Other current liabilities:	March 31, 2022		December 31, 2021
Accrued interest	$	71.5	$	47.2
Accrued wages and benefits, including taxes	9.6		33.1
Accrued ad valorem taxes	12.6		28.3
Capital expenditure accruals	22.2		23.2
Deferred revenue	24.1		3.7
Short-term lease liability	20.3		18.1
Installment payable (1)	10.0		10.0
Inactive easement commitment (2)	9.9		9.8
Operating expense accruals	11.7		9.6
Other	23.5		19.9
Other current liabilities	$	215.4	$	202.9

____________________________

(1)Consideration paid for the acquisition of Amarillo Rattler, LLC included an installment payable, which was paid on April 30, 2022.

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

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(14) 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 encountered customer billing disputes related to the delivery of gas during the storm, including one that resulted in litigation. The litigation is between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC (“Koch”) in the 162nd District Court in Dallas County, Texas. The dispute centers on whether EnLink Gas was excused from delivering gas or performing under certain delivery or purchase obligations during Winter Storm Uri, given our declaration of force majeure during the storm. Koch has invoiced us approximately $53.9 million (after subtracting amounts owed to EnLink Gas) and does not recognize the declaration of force majeure. We believe the declaration of force majeure was valid and appropriate and we intend to vigorously defend against Koch’s claims.

Another of our subsidiaries, EnLink Energy GP, LLC, is also involved in litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currently pending in Harris County, Texas, in which multiple individual plaintiffs assert personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators,

transmission/distribution utility, retail electric provider, and natural gas defendants across over 150 filed cases. We believe the claims against our subsidiary lack merit and we intend to vigorously defend against such claims.

In addition, we are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations, or cash flows. We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.

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Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2022
Accounting Policies [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.
Revenue Recognition	Revenue RecognitionThe following table summarizes the contractually committed fees (in millions) 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. 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. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

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Significant Accounting Polices (Tables)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The following table summarizes the contractually committed fees (in millions) 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. 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. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed Fees	Commitments
2022 (remaining)	$	110.3
2023	132.0
2024	112.0
2025	65.1
2026	57.9
Thereafter	289.7
Total	$	767.0

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Intangible Assets (Tables)

3 Months Ended

Mar. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of Changes in Carrying Value

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

	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Three Months Ended March 31, 2022
Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7
Amortization expense	—		(32.8)		(32.8)
Customer relationships, end of period	$	1,844.8	$	(827.9)	$	1,016.9

Schedule of Amortization Expense

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

2022 (remaining)	$	95.6
2023	127.6
2024	127.6
2025	110.2
2026	106.3
Thereafter	449.6
Total	$	1,016.9

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Summary of Debt

As of March 31, 2022 and December 31, 2021, long-term debt consisted of the following (in millions):

	March 31, 2022						December 31, 2021
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Consolidated Credit Facility due 2024 (1)	$	—	$	—	$	—	$	15.0	$	—	$	15.0
AR Facility due 2024 (2)	315.0		—		315.0		350.0		—		350.0
ENLK’s 4.40% Senior unsecured notes due 2024	521.8		0.6		522.4		521.8		0.7		522.5
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.4)		720.4
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.3)		490.7
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.4)		444.6		450.0		(5.5)		444.5
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,347.3	$	(5.8)	4,341.5		$	4,397.3	$	(5.8)	4,391.5
Debt issuance cost (3)					(26.5)						(27.8)
Long-term debt, net of unamortized issuance cost					$	4,315.0					$	4,363.7

____________________________

(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2021.

(2)Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.5% and 1.2% at March 31, 2022 and December 31, 2021, respectively.

(3)Net of accumulated amortization of $19.7 million and $18.4 million at March 31, 2022 and December 31, 2021, respectively.

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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

	Three Months Ended March 31,
	2022		2021
Current income tax expense	$	(0.2)	$	(0.1)
Deferred income tax expense	(3.0)		(1.3)
Income tax expense	$	(3.2)	$	(1.4)

Reconciliation of Total Income Tax Expense to Income before Income Taxes

The following schedule reconciles income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions):

	Three Months Ended March 31,
	2022		2021
Expected income tax benefit (expense) based on federal statutory rate	$	(8.1)	$	2.4
State income tax benefit (expense), net of federal benefit	(1.1)		0.2
Unit-based compensation (1)	(2.0)		(2.5)
Change in valuation allowance	7.1		(1.2)
Other	0.9		(0.3)
Income tax expense	$	(3.2)	$	(1.4)

____________________________

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

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Certain Provisions of the ENLK Partnership Agreement (Tables)

3 Months Ended

Mar. 31, 2022

Partners' Capital [Abstract]

Summary of Distribution Activity

A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2022 and 2021 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)
2021
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed.

(2)In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 is payable May 13, 2022.

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Members' Equity (Tables)

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Limited Partner Unit

The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):

	Three Months Ended March 31,
	2022		2021
Distributed earnings allocated to:
Common units (1)	$	54.4	$	45.9
Unvested restricted units (1)	1.1		1.1
Total distributed earnings	$	55.5	$	47.0
Undistributed loss allocated to:
Common units	$	(19.9)	$	(58.3)
Unvested restricted units	(0.4)		(1.4)
Total undistributed loss	$	(20.3)	$	(59.7)
Net income (loss) attributable to ENLC allocated to:
Common units	$	34.5	$	(12.4)
Unvested restricted units	0.7		(0.3)
Total net income (loss) attributable to ENLC	$	35.2	$	(12.7)
Net income (loss) attributable to ENLC per unit:
Basic	$	0.07	$	(0.03)
Diluted	$	0.07	$	(0.03)

____________________________

(1)Represents distribution activity consistent with the distribution activity table below.

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

	Three Months Ended March 31,
	2022	2021
Basic weighted average units outstanding:
Weighted average common units outstanding	484.0	490.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	484.0	490.0
Dilutive effect of non-vested restricted units (1)	6.6	—
Total weighted average diluted common units outstanding	490.6	490.0

____________________________

(1)All common unit equivalents were antidilutive for the three months ended March 31, 2021, since a net loss existed for that period.

Summary of Distribution Activity

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2022 and 2021, respectively, is provided below:

Declaration period	Distribution/unit		Date paid/payable
2022
Fourth Quarter of 2021	$	0.11250	February 11, 2022
First Quarter of 2022	$	0.11250	May 13, 2022
2021
Fourth Quarter of 2020	$	0.09375	February 12, 2021
First Quarter of 2021	$	0.09375	May 14, 2021

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Employee Incentive Plans (Tables)

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Schedule of Amounts Recognized in Consolidated Financial Statements

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

	Three Months Ended March 31,
	2022		2021
Cost of unit-based compensation charged to operating expense	$	1.6	$	1.7
Cost of unit-based compensation charged to general and administrative expense	5.0		4.8
Total unit-based compensation expense	$	6.6	$	6.5
Amount of related income tax benefit recognized in net income (1)	$	1.6	$	1.5

____________________________

(1)For the three months ended March 31, 2022 and 2021, the amount of related income tax benefit recognized in net income excluded $2.0 million and $2.5 million, respectively, of income tax expense related to book-to-tax differences recorded upon the vesting of restricted units.

Schedule Of Restricted Stock Units Activity, ENLC

A summary of the restricted incentive unit activity for the three months ended March 31, 2022 is provided below:

	Three Months Ended March 31, 2022
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	7,507,471		$	5.46
Granted (1)	1,761,711		8.87
Vested (1)(2)	(1,032,738)		10.35
Forfeited	(2,022)		3.71
Non-vested, end of period	8,234,422		$	5.58
Aggregate intrinsic value, end of period (in millions)	$	79.5

____________________________

(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included 278,866 units withheld for payroll taxes paid on behalf of employees.

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

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions):

	Three Months Ended March 31,
ENLC Restricted Incentive Units:	2022		2021
Aggregate intrinsic value of units vested	$	7.6	$	3.0
Fair value of units vested	$	10.7	$	10.2

Summary of Performance Units, ENLC

The following table presents a summary of the performance units:

	Three Months Ended March 31, 2022
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	3,574,827		$	6.40
Granted	598,286		11.45
Vested (1)	(708,361)		15.57
Non-vested, end of period	3,464,752		$	5.40
Aggregate intrinsic value, end of period (in millions)	$	33.4

____________________________

(1)Vested units included 273,357 units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions).

	Three Months Ended March 31,
ENLC Performance Units:	2022		2021
Aggregate intrinsic value of units vested	$	5.6	$	0.6
Fair value of units vested	$	11.0	$	4.4

Summary of Grant-Date Fair Values

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

ENLC Performance Units:	March 2022 (1)			January 2021
Grant-date fair value	$	11.90		$	4.70
Beginning TSR price	$	8.83		$	3.71
Risk-free interest rate	2.15		%	0.17		%
Volatility factor	75.00		%	71.00		%

____________________________

(1)Excludes ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Components of Gain (Loss) on Derivative Activity

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

	Three Months Ended March 31,
	2022		2021
Change in fair value of interest rate swaps	$	0.1	$	4.7
Tax expense	—		(1.1)
Unrealized gain on designated cash flow hedge	$	0.1	$	3.6

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):

	Three Months Ended March 31,
	2022		2021
Interest expense	$	0.1	$	4.8

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

	Three Months Ended March 31,
	2022		2021
Change in fair value of derivatives	$	(15.1)	$	(7.9)
Realized loss on derivatives	(16.1)		(75.5)
Loss on derivative activity	$	(31.2)	$	(83.4)

Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps

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

	March 31, 2022		December 31, 2021
Fair value of derivative assets—current	$	68.1	$	22.4
Fair value of derivative assets—long-term	0.1		0.2
Fair value of derivative liabilities—current	(97.2)		(34.9)
Fair value of derivative liabilities—long-term	(0.6)		(2.2)
Net fair value of commodity swaps	$	(29.6)	$	(14.5)

Notional Amount and Fair Value of Derivative Instruments

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at March 31, 2022 (in millions). The remaining term of the contracts extend no later than July 2023.

		March 31, 2022
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gals	(181.4)	$	(29.7)
Natural gas (short contracts)	Swaps	MMbtu	(3.7)	(3.9)
Natural gas (long contracts)	Swaps	MMbtu	2.8	2.9
Crude and condensate (short contracts)	Swaps	MMbbls	(4.7)	(59.3)
Crude and condensate (long contracts)	Swaps	MMbbls	4.0	60.4
Total fair value of commodity swaps				$	(29.6)

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

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

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

	Level 2
	March 31, 2022		December 31, 2021
Commodity swaps (1)	$	(29.6)	$	(14.5)

____________________________

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

Schedule of the Estimated Fair Value of Financial Instruments

Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):

	March 31, 2022				December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,315.0	$	4,154.6	$	4,363.7	$	4,520.0
Installment payable (2)	$	10.0	$	10.0	$	10.0	$	10.0
Contingent consideration (2)	$	6.9	$	6.9	$	6.9	$	6.9

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $26.5 million and $27.8 million as of March 31, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration paid for the acquisition of Amarillo Rattler, LLC included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Summary of Financial Information

We evaluate the performance of our operating segments based on segment 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		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2022
Natural gas sales	$	195.6	$	211.5	$	76.3	$	25.4	$	—	$	508.8
NGL sales	—		1,151.5		3.1		(0.1)		—		1,154.5
Crude oil and condensate sales	272.0		73.9		34.7		—		—		380.6
Product sales	467.6		1,436.9		114.1		25.3		—		2,043.9
NGL sales—related parties	399.8		36.9		208.1		146.9		(791.7)		—
Crude oil and condensate sales—related parties	—		—		0.3		3.0		(3.3)		—
Product sales—related parties	399.8		36.9		208.4		149.9		(795.0)		—
Gathering and transportation	13.6		16.3		42.7		38.8		—		111.4
Processing	7.8		0.5		25.4		27.6		—		61.3
NGL services	—		23.9		—		—		—		23.9
Crude services	4.3		9.4		3.7		0.2		—		17.6
Other services	0.2		0.4		0.1		0.1		—		0.8
Midstream services	25.9		50.5		71.9		66.7		—		215.0
Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	—		0.1		—		—		(0.1)		—
Revenue from contracts with customers	893.3		1,524.4		394.4		241.9		(795.1)		2,258.9
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(766.7)		(1,388.7)		(276.8)		(157.4)		795.1		(1,794.5)
Realized loss on derivatives	(2.4)		(6.6)		(3.7)		(3.4)		—		(16.1)
Change in fair value of derivatives	(5.9)		(5.6)		(7.1)		3.5		—		(15.1)
Adjusted gross margin	118.3		123.5		106.8		84.6		—		433.2
Operating expenses	(45.3)		(33.0)		(21.0)		(21.6)		—		(120.9)
Segment profit	73.0		90.5		85.8		63.0		—		312.3
Depreciation and amortization	(36.7)		(35.5)		(50.9)		(28.4)		(1.4)		(152.9)
Gain (loss) on disposition of assets	—		0.2		0.2		(5.5)		—		(5.1)
General and administrative	—		—		—		—		(29.0)		(29.0)
Interest expense, net of interest income	—		—		—		—		(55.1)		(55.1)
Loss from unconsolidated affiliate investments	—		—		—		—		(1.1)		(1.1)
Other income	—		—		—		—		0.1		0.1
Income (loss) before non-controlling interest and income taxes	$	36.3	$	55.2	$	35.1	$	29.1	$	(86.5)	$	69.2
Capital expenditures	$	34.2	$	5.7	$	15.4	$	3.1	$	1.6	$	60.0

____________________________

(1)Includes related party cost of sales of $10.6 million for the three months ended March 31, 2022.

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2021
Natural gas sales	$	125.0	$	121.2	$	35.9	$	51.0	$	—	$	333.1
NGL sales	—		626.0		0.6		1.2		—		627.8
Crude oil and condensate sales	107.3		41.1		13.6		—		—		162.0
Product sales	232.3		788.3		50.1		52.2		—		1,122.9
NGL sales—related parties	164.9		23.6		113.1		80.9		(382.5)		—
Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—
Product sales—related parties	164.9		23.6		113.1		82.4		(384.0)		—
Gathering and transportation	9.7		15.8		51.3		40.4		—		117.2
Processing	8.2		0.5		15.9		27.1		—		51.7
NGL services	—		22.0		—		0.1		—		22.1
Crude services	3.5		9.9		3.3		0.2		—		16.9
Other services	0.2		0.5		0.2		0.1		—		1.0
Midstream services	21.6		48.7		70.7		67.9		—		208.9
Crude services—related parties	—		—		0.1		—		(0.1)		—
Other services—related parties	—		2.3		—		—		(2.3)		—
Midstream services—related parties	—		2.3		0.1		—		(2.4)		—
Revenue from contracts with customers	418.8		862.9		234.0		202.5		(386.4)		1,331.8
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	(56.9)		(10.7)		(6.0)		(1.9)		—		(75.5)
Change in fair value of derivatives	(5.3)		(0.4)		(1.8)		(0.4)		—		(7.9)
Adjusted gross margin	31.0		111.4		75.2		96.1		—		313.7
Operating expenses	11.8		(29.2)		(19.7)		(19.2)		—		(56.3)
Segment profit	42.8		82.2		55.5		76.9		—		257.4
Depreciation and amortization	(33.5)		(36.1)		(50.7)		(28.7)		(2.0)		(151.0)
Gain (loss) on disposition of assets	0.1		(0.1)		—		—		—		—
General and administrative	—		—		—		—		(26.0)		(26.0)
Interest expense, net of interest income	—		—		—		—		(60.0)		(60.0)
Loss from unconsolidated affiliate investments	—		—		—		—		(6.3)		(6.3)
Other loss	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	$	9.4	$	46.0	$	4.8	$	48.2	$	(94.4)	$	14.0
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.

Schedule of Segment Assets

The table below represents information about segment assets as of March 31, 2022 and December 31, 2021 (in millions):

Segment Identifiable Assets:	March 31, 2022		December 31, 2021
Permian	$	2,500.2	$	2,358.6
Louisiana	2,442.9		2,428.6
Oklahoma	2,582.9		2,619.5
North Texas	866.8		896.8
Corporate (1)	247.4		179.7
Total identifiable assets	$	8,640.2	$	8,483.2

____________________________(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.

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Other Information (Tables)

3 Months Ended

Mar. 31, 2022

Other Liabilities Disclosure [Abstract]

Schedule of Other Current Liabilities

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

Other current assets:	March 31, 2022		December 31, 2021
Natural gas and NGLs inventory	$	73.6	$	49.4
Prepaid expenses and other	39.1		34.2
Other current assets	$	112.7	$	83.6

Other current liabilities:	March 31, 2022		December 31, 2021
Accrued interest	$	71.5	$	47.2
Accrued wages and benefits, including taxes	9.6		33.1
Accrued ad valorem taxes	12.6		28.3
Capital expenditure accruals	22.2		23.2
Deferred revenue	24.1		3.7
Short-term lease liability	20.3		18.1
Installment payable (1)	10.0		10.0
Inactive easement commitment (2)	9.9		9.8
Operating expense accruals	11.7		9.6
Other	23.5		19.9
Other current liabilities	$	215.4	$	202.9

____________________________

(1)Consideration paid for the acquisition of Amarillo Rattler, LLC included an installment payable, which was paid on April 30, 2022.

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

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General (Details)	3 Months Ended
	Mar. 31, 2022 Bcf / d fractionator processingPlant mi bbl
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of miles of pipeline | mi	12,100
Number of natural gas processing plants | processingPlant	22
Amount of processing capacity | Bcf / d	5.5
Number of fractionators | fractionator	7
Capacity of fractionators per day, barrels | bbl	320,000

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Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Mar. 31, 2022 USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 767.0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 110.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 132.0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 112.0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 65.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 57.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 289.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	5 years

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Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 32.8	$ 30.9
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets	10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets	20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets	14 years 10 months 24 days

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Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance	$ 1,844.8
Accumulated Amortization, Beginning Balance	(795.1)
Net Carrying Amount, Beginning Balance	1,049.7
Amortization expense	(32.8)	$ (30.9)
Gross Carrying Amount, Ending Balance	1,844.8
Accumulated Amortization, Ending Balance	(827.9)
Net Carrying Amount, Ending Balance	$ 1,016.9

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Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
2022	$ 95.6
2023	127.6
2024	127.6
2025	110.2
2026	106.3
Thereafter	449.6
Total	$ 1,016.9	$ 1,049.7

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Related Party Transactions (Details) - USD ($)		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	$ 1,794,500,000	$ 934,700,000
Accounts payable to related party		5,800,000		$ 1,600,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization		10,600,000	3,200,000
Accounts payable to related party		5,800,000		$ 1,600,000
GIP
Related Party Transaction [Line Items]
General and administrative expenses from transactions with related party		$ 0	$ 100,000

[1] Includes related party cost of sales of $10.6 million and $3.2 million for the three months ended March 31, 2022 and 2021, respectively.

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Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Debt Instrument
Outstanding Principal	$ 4,347.3	$ 4,397.3
Premium (Discount)	(5.8)	(5.8)
Long-Term Debt	4,341.5	4,391.5
Debt issuance costs	(26.5)	(27.8)
Long-term debt, net of unamortized issuance cost	4,315.0	4,363.7
Debt issuance cost accumulated amortization	19.7	18.4
Consolidated Credit Facility due 2024
Debt Instrument
Outstanding Principal	0.0	15.0
Premium (Discount)	0.0	0.0
Long-Term Debt	0.0	15.0
AR Facility due 2024
Debt Instrument
Outstanding Principal	315.0	350.0
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 315.0	$ 350.0
Effective interest rate	1.50%	1.20%
4.4% Senior Notes Due 2024
Debt Instrument
Outstanding Principal	$ 521.8	$ 521.8
Premium (Discount)	0.6	0.7
Long-Term Debt	$ 522.4	522.5
Stated interest rate	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding Principal	$ 720.8	720.8
Premium (Discount)	(0.4)	(0.4)
Long-Term Debt	$ 720.4	720.4
Stated interest rate	4.15%
4.85 Senior Notes Due 2026
Debt Instrument
Outstanding Principal	$ 491.0	491.0
Premium (Discount)	(0.3)	(0.3)
Long-Term Debt	$ 490.7	490.7
Stated interest rate	4.85%
5.625% Senior unsecured notes due 2028
Debt Instrument
Outstanding Principal	$ 500.0	500.0
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 500.0	500.0
Stated interest rate	5.625%
5.375% Senior Notes Due 2029
Debt Instrument
Outstanding Principal	$ 498.7	498.7
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 498.7	498.7
Stated interest rate	5.375%
5.6% Senior Notes Due 2044
Debt Instrument
Outstanding Principal	$ 350.0	350.0
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 349.8	349.8
Stated interest rate	5.60%
5.05 Senior Notes Due 2045
Debt Instrument
Outstanding Principal	$ 450.0	450.0
Premium (Discount)	(5.4)	(5.5)
Long-Term Debt	$ 444.6	444.5
Stated interest rate	5.05%
Senior Notes, 5.45%, Due 2047
Debt Instrument
Outstanding Principal	$ 500.0	500.0
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9
Stated interest rate	5.45%
Term Loan Due 2021
Debt Instrument
Effective interest rate		3.90%

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Long-Term Debt - Narrative (Details)	3 Months Ended
	Mar. 31, 2022 USD ($)
Debt Instrument
Increase (decrease) in accounts receivable	$ 882,600,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity	350,000,000
Accounts receivable securitization facility, outstanding amount	315,000,000
Letters of credit
Debt Instrument
Additional amount available (not to exceed)	1,750,000,000
Line of credit facility, fair value of amount outstanding	0
Letters of credit | Letter of Credit | ENLC
Debt Instrument
Line of credit facility, fair value of amount outstanding	44,300,000
Letter of Credit | Letters of credit
Debt Instrument
Maximum borrowing capacity	$ 500,000,000

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Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.2)	$ (0.1)
Deferred income tax expense	(3.0)	(1.3)
Income tax expense	(3.2)	(1.4)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit (expense) based on federal statutory rate	(8.1)	2.4
State income tax benefit (expense), net of federal benefit	(1.1)	0.2
Unit-based compensation	(2.0)	(2.5)
Change in valuation allowance	7.1	(1.2)
Other	0.9	(0.3)
Income tax expense	$ (3.2)	$ (1.4)

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ (140.5)	$ (137.5)
Deferred tax assets	484.8	481.6
Deferred tax assets, valuation allowance	$ 144.5	$ 151.6

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Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Jan. 31, 2022	Dec. 31, 2021	Mar. 31, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Partnership agreement
Total consideration paid			$ 50.5		$ 0.0
Series B Preferred Unitholders
Partnership agreement
Stock redeemed during period (in shares)			3,333,334
Total consideration paid			$ 50.5
Redemption price of preferred stock, percent			10100.00%
Distribution paid-in kind (in shares)			0	0	150,871	150,494
Cash distributions			$ 17.5	$ 19.2	$ 17.0	$ 16.9
Series B Preferred Unitholders | Limited Partner | Fourth Quarter of 2021
Partnership agreement
Distributions preferred units	$ 1.0	$ 0.9
Series B Preferred Unitholders | Limited Partner | First Quarter of 2022
Partnership agreement
Distributions preferred units	$ 0.3		$ 17.2
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		57,501,693	54,168,359	57,501,693
Preferred units, outstanding (in shares)		57,501,693	54,168,359	57,501,693
Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		400,000	400,000	400,000
Preferred units, outstanding (in shares)		400,000	400,000	400,000

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Members' Equity - Computation and Distribution Activity (Details) - USD ($)		3 Months Ended
	May 02, 2022	Mar. 31, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020	Nov. 30, 2020
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Repurchase program, amount authorized						$ 100,000,000
Common units repurchased (in shares)		2,093,842		0
Payment for common unit repurchases		$ 17,000,000.0		$ 0
Shares repurchased, average cost per share (in dollars per share)		$ 8.12
Distributed earnings allocated to:
Total distributed earnings		$ 55,500,000		47,000,000.0
Undistributed loss allocated to:
Total undistributed loss, basic		(20,300,000)		(59,700,000)
Total undistributed loss, diluted		(20,300,000)		(59,700,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic		35,200,000		(12,700,000)
Total net income (loss), diluted		$ 35,200,000		$ (12,700,000)
Net income (loss) attributable to ENLC per unit:
Basic (in dollars per share)		$ 0.07		$ (0.03)
Diluted (in dollars per share)		0.07		(0.03)
Distribution declared/unit (in dollars per share)		$ 0.11250	$ 0.11250	$ 0.09375	$ 0.09375
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units repurchased (in shares)	675,095
Payment for common unit repurchases	$ 6,000,000
Shares repurchased, average cost per share (in dollars per share)	$ 8.92
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings		$ 1,100,000		$ 1,100,000
Undistributed loss allocated to:
Total undistributed loss, basic		(400,000)		(1,400,000)
Total undistributed loss, diluted		(400,000)		(1,400,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic		700,000		(300,000)
Total net income (loss), diluted		700,000		(300,000)
Common units
Distributed earnings allocated to:
Total distributed earnings		54,400,000		45,900,000
Undistributed loss allocated to:
Total undistributed loss, basic		(19,900,000)		(58,300,000)
Total undistributed loss, diluted		(19,900,000)		(58,300,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic		34,500,000		(12,400,000)
Total net income (loss), diluted		$ 34,500,000		$ (12,400,000)

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Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in units)	484.0	490.0
Dilutive effect of non-vested restricted units (in units)	6.6	0.0
Total weighted average diluted common units outstanding (in units)	490.6	490.0

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Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Allocation
Total unit-based compensation expense	$ 6.6	$ 6.5
Amount of related income tax benefit recognized in net income	1.6	1.5
Unit-based compensation	2.0	2.5
Restricted units
Allocation
Unit-based compensation	2.0	2.5
Cost of unit-based compensation charged to operating expense
Allocation
Total unit-based compensation expense	1.6	1.7
Cost of unit-based compensation charged to general and administrative expense
Allocation
Total unit-based compensation expense	$ 5.0	$ 4.8

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Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended
	Mar. 31, 2022	Jan. 31, 2021	Mar. 31, 2022	Mar. 31, 2021
Unvested restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)			7,507,471
Granted (in shares)	193,935		1,761,711
Vested (in shares)			(1,032,738)
Forfeited (in shares)			(2,022)
Non-vested, end of period (in shares)	8,234,422		8,234,422
Aggregate intrinsic value, end of period	$ 79.5		$ 79.5
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)			$ 5.46
Granted (in dollars per share)			8.87
Vested (in dollars per share)			10.35
Forfeited (in dollars per share)			3.71
Non-vested, end of period (in dollars per share)	$ 5.58		$ 5.58
Incentive unit award vesting period			3 years
Units withheld for payroll taxes (in shares)			278,866
Aggregate intrinsic value of units vested			$ 7.6	$ 3.0
Fair value of units vested	$ 1.7		10.7	10.2
Unrecognized compensation cost related to non-vested restricted incentive units	$ 24.5		$ 24.5
Unrecognized compensation costs, weighted average period for recognition			2 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grants in period	193,935		1,761,711
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)			3,574,827
Granted (in shares)			598,286
Vested (in shares)			(708,361)
Non-vested, end of period (in shares)	3,464,752		3,464,752
Aggregate intrinsic value, end of period	$ 33.4		$ 33.4
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)			$ 6.40
Granted (in dollars per share)			11.45
Vested (in dollars per share)			15.57
Non-vested, end of period (in dollars per share)	$ 5.40		$ 5.40
Units withheld for payroll taxes (in shares)			273,357
Aggregate intrinsic value of units vested			$ 5.6	0.6
Fair value of units vested			11.0	$ 4.4
Unrecognized compensation cost related to non-vested restricted incentive units	$ 15.5		$ 15.5
Unrecognized compensation costs, weighted average period for recognition			1 year 10 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)	$ 11.90	$ 4.70
Beginning TSR Price (in dollars per share)	$ 8.83	$ 3.71
Risk-free interest rate	2.15%	0.17%
Volatility factor	75.00%	71.00%
Grants in period			598,286
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting			0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting			200.00%
Performance Shares With Vesting Conditions
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in shares)			88,863
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)	$ 8.90
Grants in period			88,863

XML

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021
Derivatives
Tax expense			$ (1.1)
Unrealized gain on designated cash flow hedge	[1]	$ 0.1	3.6	[2]
Interest expense		0.1	4.8
Interest expense expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months		0.1
Interest rate swaps
Derivatives
Change in fair value of interest rate swaps		0.1	4.7
Tax expense		0.0	(1.1)
Unrealized gain on designated cash flow hedge		$ 0.1	$ 3.6

[1] Includes tax expense of $1.1 million for the three months ended March 31, 2021.

[2] Includes tax expense of $1.1 million.

XML

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Derivatives
Change in fair value of derivatives	$ (15.1)	$ (7.9)
Loss on derivative activity	(31.2)	(83.4)
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	(15.1)	(7.9)
Realized loss on derivatives	(16.1)	(75.5)
Loss on derivative activity	$ (31.2)	$ (83.4)

XML

Derivatives - Fair Value of Commodity Swap Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Derivatives
Fair value of derivative assets—current	$ 68.1	$ 22.4
Fair value of derivative assets—long-term	0.1	0.2
Fair value of derivative liabilities—current	(97.2)	(34.9)
Fair value of derivative liabilities—long-term	(0.6)	(2.2)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	68.1	22.4
Fair value of derivative assets—long-term	0.1	0.2
Fair value of derivative liabilities—current	(97.2)	(34.9)
Fair value of derivative liabilities—long-term	(0.6)	(2.2)
Net fair value of commodity swaps	$ (29.6)	$ (14.5)

XML

Derivatives - Commodity Swaps Additional Information (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions	3 Months Ended
	Mar. 31, 2022 USD ($) MMBTU MMBbls gal	Dec. 31, 2021 USD ($)
Derivatives
Net Fair Value	$ (29,600,000)	$ (14,500,000)
Commodity
Derivatives
Net Fair Value	(29,600,000)
Maximum loss if counterparties fail to perform	68,200,000
Possible reduction in maximum loss if counterparties fail to perform	$ 700,000
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	181.4
Net Fair Value	$ (29,700,000)
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	3.7
Net Fair Value	$ (3,900,000)
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	2.8
Net Fair Value	$ 2,900,000
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	4.7
Net Fair Value	$ (59,300,000)
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	4.0
Net Fair Value	$ 60,400,000

XML

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Level 2 | Commodity swaps | Recurring
Fair Value
Net Fair Value	$ (29.6)	$ (14.5)

XML

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021	Apr. 30, 2021
Fair Value
Debt issuance costs	$ 26.5	$ 27.8
Amarillo Rattler, LLC
Fair Value
Installment payable	10.0
Business combination, maximum earnout			$ 15.0
Carrying Value
Fair Value
Long-term debt	4,315.0	4,363.7
Installment payable	10.0	10.0
Contingent consideration fair value	6.9	6.9
Fair Value
Fair Value
Long-term debt	4,154.6	4,520.0
Installment payable	10.0	10.0
Contingent consideration fair value	$ 6.9	$ 6.9

XML

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2022	Mar. 31, 2021
Segment Reporting
Revenue from contracts with customers		$ 2,258.9	$ 1,331.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	(1,794.5)	(934.7)
Realized loss on derivatives		(16.1)	(75.5)
Change in fair value of derivatives		(15.1)	(7.9)
Adjusted gross margin		433.2	313.7
Operating expenses		(120.9)	(56.3)
Segment profit		312.3	257.4
Depreciation and amortization		(152.9)	(151.0)
Gain (loss) on disposition of assets		(5.1)	0.0
General and administrative		(29.0)	(26.0)
Interest expense, net of interest income		(55.1)	(60.0)
Income (loss) from unconsolidated affiliates		(1.1)	(6.3)
Other income (expense)		0.1	(0.1)
Income before non-controlling interest and income taxes		69.2	14.0
Capital expenditures		60.0	20.8
Related parties amount in cost of sales		10.6	3.2
Permian
Segment Reporting
Revenue from contracts with customers		893.3	418.8
Cost of sales, exclusive of operating expenses and depreciation and amortization		(766.7)	(325.6)
Realized loss on derivatives		(2.4)	(56.9)
Change in fair value of derivatives		(5.9)	(5.3)
Adjusted gross margin		118.3	31.0
Operating expenses		(45.3)	11.8
Segment profit		73.0	42.8
Depreciation and amortization		(36.7)	(33.5)
Gain (loss) on disposition of assets		0.0	0.1
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Income (loss) from unconsolidated affiliates		0.0	0.0
Other income (expense)		0.0	0.0
Income before non-controlling interest and income taxes		36.3	9.4
Capital expenditures		34.2	13.3
Louisiana
Segment Reporting
Revenue from contracts with customers		1,524.4	862.9
Cost of sales, exclusive of operating expenses and depreciation and amortization		(1,388.7)	(740.4)
Realized loss on derivatives		(6.6)	(10.7)
Change in fair value of derivatives		(5.6)	(0.4)
Adjusted gross margin		123.5	111.4
Operating expenses		(33.0)	(29.2)
Segment profit		90.5	82.2
Depreciation and amortization		(35.5)	(36.1)
Gain (loss) on disposition of assets		0.2	(0.1)
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Income (loss) from unconsolidated affiliates		0.0	0.0
Other income (expense)		0.0	0.0
Income before non-controlling interest and income taxes		55.2	46.0
Capital expenditures		5.7	2.8
Oklahoma
Segment Reporting
Revenue from contracts with customers		394.4	234.0
Cost of sales, exclusive of operating expenses and depreciation and amortization		(276.8)	(151.0)
Realized loss on derivatives		(3.7)	(6.0)
Change in fair value of derivatives		(7.1)	(1.8)
Adjusted gross margin		106.8	75.2
Operating expenses		(21.0)	(19.7)
Segment profit		85.8	55.5
Depreciation and amortization		(50.9)	(50.7)
Gain (loss) on disposition of assets		0.2	0.0
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Income (loss) from unconsolidated affiliates		0.0	0.0
Other income (expense)		0.0	0.0
Income before non-controlling interest and income taxes		35.1	4.8
Capital expenditures		15.4	1.9
North Texas
Segment Reporting
Revenue from contracts with customers		241.9	202.5
Cost of sales, exclusive of operating expenses and depreciation and amortization		(157.4)	(104.1)
Realized loss on derivatives		(3.4)	(1.9)
Change in fair value of derivatives		3.5	(0.4)
Adjusted gross margin		84.6	96.1
Operating expenses		(21.6)	(19.2)
Segment profit		63.0	76.9
Depreciation and amortization		(28.4)	(28.7)
Gain (loss) on disposition of assets		(5.5)	0.0
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Income (loss) from unconsolidated affiliates		0.0	0.0
Other income (expense)		0.0	0.0
Income before non-controlling interest and income taxes		29.1	48.2
Capital expenditures		3.1	2.4
Corporate
Segment Reporting
Revenue from contracts with customers		(795.1)	(386.4)
Cost of sales, exclusive of operating expenses and depreciation and amortization		795.1	386.4
Realized loss on derivatives		0.0	0.0
Change in fair value of derivatives		0.0	0.0
Adjusted gross margin		0.0	0.0
Operating expenses		0.0	0.0
Segment profit		0.0	0.0
Depreciation and amortization		(1.4)	(2.0)
Gain (loss) on disposition of assets		0.0	0.0
General and administrative		(29.0)	(26.0)
Interest expense, net of interest income		(55.1)	(60.0)
Income (loss) from unconsolidated affiliates		(1.1)	(6.3)
Other income (expense)		0.1	(0.1)
Income before non-controlling interest and income taxes		(86.5)	(94.4)
Capital expenditures		1.6	0.4
Product sales
Segment Reporting
Revenue from contracts with customers		2,043.9	1,122.9
Product sales | Permian
Segment Reporting
Revenue from contracts with customers		467.6	232.3
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers		1,436.9	788.3
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		114.1	50.1
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers		25.3	52.2
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers		508.8	333.1
Product sales, Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers		195.6	125.0
Product sales, Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers		211.5	121.2
Product sales, Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		76.3	35.9
Product sales, Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers		25.4	51.0
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers		1,154.5	627.8
Product sales, NGL sales | Permian
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers		1,151.5	626.0
Product sales, NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		3.1	0.6
Product sales, NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers		(0.1)	1.2
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers		380.6	162.0
Product sales, Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers		272.0	107.3
Product sales, Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers		73.9	41.1
Product sales, Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		34.7	13.6
Product sales, Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers		399.8	164.9
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		36.9	23.6
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		208.4	113.1
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		149.9	82.4
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(795.0)	(384.0)
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, NGL sales, related party | Permian
Segment Reporting
Revenue from contracts with customers		399.8	164.9
Product sales, NGL sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		36.9	23.6
Product sales, NGL sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		208.1	113.1
Product sales, NGL sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers		146.9	80.9
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(791.7)	(382.5)
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, Crude oil and condensate sales, related party | Permian
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, Crude oil and condensate sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Product sales, Crude oil and condensate sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.3	0.0
Product sales, Crude oil and condensate sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers		3.0	1.5
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(3.3)	(1.5)
Midstream services
Segment Reporting
Revenue from contracts with customers		215.0	208.9
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers		25.9	21.6
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers		50.5	48.7
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers		71.9	70.7
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers		66.7	67.9
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers		111.4	117.2
Midstream services, Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers		13.6	9.7
Midstream services, Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers		16.3	15.8
Midstream services, Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers		42.7	51.3
Midstream services, Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers		38.8	40.4
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers		61.3	51.7
Midstream services, Processing | Permian
Segment Reporting
Revenue from contracts with customers		7.8	8.2
Midstream services, Processing | Louisiana
Segment Reporting
Revenue from contracts with customers		0.5	0.5
Midstream services, Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers		25.4	15.9
Midstream services, Processing | North Texas
Segment Reporting
Revenue from contracts with customers		27.6	27.1
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers		23.9	22.1
Midstream services, NGL services | Permian
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers		23.9	22.0
Midstream services, NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, NGL services | North Texas
Segment Reporting
Revenue from contracts with customers		0.0	0.1
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers		17.6	16.9
Midstream services, Crude services | Permian
Segment Reporting
Revenue from contracts with customers		4.3	3.5
Midstream services, Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers		9.4	9.9
Midstream services, Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers		3.7	3.3
Midstream services, Crude services | North Texas
Segment Reporting
Revenue from contracts with customers		0.2	0.2
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers		0.8	1.0
Midstream services, Other services | Permian
Segment Reporting
Revenue from contracts with customers		0.2	0.2
Midstream services, Other services | Louisiana
Segment Reporting
Revenue from contracts with customers		0.4	0.5
Midstream services, Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1	0.2
Midstream services, Other services | North Texas
Segment Reporting
Revenue from contracts with customers		0.1	0.1
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0.1	2.3
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0	0.1
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(0.1)	(2.4)
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers			0.0
Midstream services, Crude services, related party | Permian
Segment Reporting
Revenue from contracts with customers			0.0
Midstream services, Crude services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers			0.0
Midstream services, Crude services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers			0.1
Midstream services, Crude services, related party | North Texas
Segment Reporting
Revenue from contracts with customers			0.0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers			(0.1)
Midstream services, Other services, related party
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers			(2.3)
Midstream services, Other services, related party | Permian
Segment Reporting
Revenue from contracts with customers		0.0
Midstream services, Other services, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers			0.0
Midstream services, Other services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		0.1
Midstream services, Other services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers			2.3
Midstream services, Other services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0
Midstream services, Other services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers			0.0
Midstream services, Other services, related party | North Texas
Segment Reporting
Revenue from contracts with customers		0.0
Midstream services, Other services, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers			$ 0.0
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		$ (0.1)

[1] Includes related party cost of sales of $10.6 million and $3.2 million for the three months ended March 31, 2022 and 2021, respectively.

XML

Segment Information - Assets (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Segment Reporting
Total identifiable assets	$ 8,640.2	$ 8,483.2
Permian
Segment Reporting
Total identifiable assets	2,500.2	2,358.6
Louisiana
Segment Reporting
Total identifiable assets	2,442.9	2,428.6
Oklahoma
Segment Reporting
Total identifiable assets	2,582.9	2,619.5
North Texas
Segment Reporting
Total identifiable assets	866.8	896.8
Corporate
Segment Reporting
Total identifiable assets	$ 247.4	$ 179.7

XML

Other Information (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Other current assets:
Natural gas and NGLs inventory	$ 73.6	$ 49.4
Prepaid expenses and other	39.1	34.2
Other current assets	112.7	83.6
Other current liabilities:
Accrued interest	71.5	47.2
Accrued wages and benefits, including taxes	9.6	33.1
Accrued ad valorem taxes	12.6	28.3
Capital expenditure accruals	22.2	23.2
Deferred revenue	24.1	3.7
Short-term lease liability	20.3	18.1
Installment payable	10.0	10.0
Inactive easement commitment	9.9	9.8
Operating expense accruals	11.7	9.6
Other	23.5	19.9
Other current liabilities	$ 215.4	$ 202.9

XML

Commitments and Contingencies - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($) claim
Koch | EnLink Gas Marketing, LP
Commitments and Contingencies
Loss contingency, damages sought, value | $	$ 53.9
Harris County Multi-District Litigation | EnLink Energy GP, LLC
Commitments and Contingencies
Filed cases, over | claim	150