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, 2023

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 27, 2023, the Registrant had 465,989,285 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	32
3.	Quantitative and Qualitative Disclosures About Market Risk	52
4.	Controls and Procedures	54
	PART II—OTHER INFORMATION
1.	Legal Proceedings	55
1A.	Risk Factors	55
2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
6.	Exhibits	56

2

DEFINITIONS

The following terms as defined are used in this document:

Defined Term	Definition
/d	Per day.
2014 Plan	ENLC’s 2014 Long-Term Incentive Plan.
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.
Amarillo Rattler Acquisition	On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin.
AR Facility	An accounts receivable securitization facility of up to $500 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.
ASC	The Financial Accounting Standards Board Accounting Standards Codification.
ASC 718	ASC 718, Compensation—Stock Compensation.
ASC 815	ASC 815, Derivatives and Hedging.
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.
Barnett Shale	A natural gas producing shale reservoir located in North Texas.
Barnett Shale Acquisition	On July 1, 2022, we acquired all of the equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale.
Bbl	Barrel.
Bbtu	Billion British thermal units.
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.
Central Oklahoma Acquisition	On December 19, 2022, we acquired gathering and processing assets located in Central Oklahoma, including approximately 900 miles of lean and rich gas gathering pipeline and two processing plants with 280 MMcf/d of total processing capacity.
CFTC	U.S. Commodity Futures Trading Commission.
CO2	Carbon dioxide.
Commission	U.S. Securities and Exchange Commission.
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 together with its consolidated subsidiaries.
ENLC Class C Common Units	A class of non-economic ENLC common units equal to the number of Series B Preferred Units in order to provide certain voting rights with respect to ENLC to the holders of such Series B Preferred Units.
ENLK	EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries.
Exchange Act	The Securities Exchange Act of 1934, as amended.
FCDTCs	Futures and Cleared Derivatives Transactions Customer Agreements.
Federal Reserve	The Board of Governors of the Federal Reserve System of the United States.
GAAP	Generally accepted accounting principles in the United States of America.

3

Gal	Gallon.
GCF	Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. We own 38.75% of GCF. The GCF assets were temporarily idled to reduce operating expenses in 2021, but are expected to resume operations in 2024.
General Partner	EnLink Midstream GP, LLC, the general partner of ENLK.
GIP	Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.
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.
Matterhorn JV	A joint venture with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP. The Matterhorn JV is expected to construct a pipeline designed to transport up to 2.5 Bcf/d of natural gas through approximately 490 miles of 42-inch pipeline from the Waha Hub in West Texas to Katy, Texas.
Midland Basin	A large sedimentary basin in West Texas.
MMbbls	Million barrels.
MMbtu	Million British thermal units.
MMcf	Million cubic feet.
MMgals	Million gallons.
MVC	Minimum volume commitment.
NGL	Natural gas liquid.
NGP	NGP Natural Resources XI, LP.
Operating Partnership	EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
OPIS	Oil Price Information Service.
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.
Revolving Credit Facility	A $1.40 billion unsecured revolving credit facility entered into by ENLC, which includes a $500.0 million letter of credit subfacility. The Revolving Credit Facility is guaranteed by ENLK.
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.
SOFR	Secured overnight financing rate.
SPV	EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC.
STACK	Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.

4

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)

	March 31, 2023		December 31, 2022
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	72.8	$	22.6
Accounts receivable:
Trade receivables (1)	86.3		89.2
Accrued revenue and other	537.5		636.0
Fair value of derivative assets	68.5		68.4
Other current assets	94.0		166.6
Total current assets	859.1		982.8
Property and equipment, net of accumulated depreciation of $4,898.8 and $4,774.5, respectively	6,543.4		6,556.0
Intangible assets, net of accumulated amortization of $955.5 and $923.6, respectively	889.3		921.2
Investment in unconsolidated affiliates	140.4		90.2
Fair value of derivative assets	13.6		2.9
Other assets, net	100.6		97.9
Total assets	$	8,546.4	$	8,651.0
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	111.4	$	126.9
Accrued gas, NGLs, condensate, and crude oil purchases (2)	360.0		476.0
Fair value of derivative liabilities	41.1		42.9
Other current liabilities	195.9		229.6
Total current liabilities	708.4		875.4
Long-term debt, net of unamortized issuance cost	4,828.0		4,723.5
Other long-term liabilities	96.6		94.0
Deferred tax liability, net	53.2		42.7
Fair value of derivative liabilities	18.3		2.7
Members’ equity:
Members’ equity (467,137,866 and 468,980,630 units issued and outstanding, respectively)	1,238.7		1,306.4
Accumulated other comprehensive loss	(1.2)		—
Non-controlling interest	1,604.4		1,606.3
Total members’ equity	2,841.9		2,912.7
Commitments and contingencies (Note 16)
Total liabilities and members’ equity	$	8,546.4	$	8,651.0

____________________________

(1)There was no allowance for bad debt at March 31, 2023. Includes allowance for bad debt of $0.1 million at December 31, 2022.

(2)Includes related party accounts payable balances of $1.2 million and $2.5 million at March 31, 2023 and December 31, 2022, 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,
	2023		2022
	(Unaudited)
Revenues:
Product sales	$	1,476.3	$	2,043.9
Midstream services	279.3		215.0
Gain (loss) on derivative activity	11.9		(31.2)
Total revenues	1,767.5		2,227.7
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	1,271.9		1,794.5
Operating expenses	132.4		120.9
Depreciation and amortization	160.4		152.9
(Gain) loss on disposition of assets	(0.4)		5.1
General and administrative	29.5		29.0
Total operating costs and expenses	1,593.8		2,102.4
Operating income	173.7		125.3
Other income (expense):
Interest expense, net of interest income	(68.5)		(55.1)
Loss from unconsolidated affiliate investments	(0.1)		(1.1)
Other income	—		0.1
Total other expense	(68.6)		(56.1)
Income before non-controlling interest and income taxes	105.1		69.2
Income tax expense	(10.9)		(3.2)
Net income	94.2		66.0
Net income attributable to non-controlling interest	36.0		30.8
Net income attributable to ENLC	$	58.2	$	35.2
Net income attributable to ENLC per unit:
Basic common unit	$	0.12	$	0.07
Diluted common unit	$	0.12	$	0.07

____________________________

(1)Includes related party cost of sales of $1.5 million and $10.6 million for the three months ended March 31, 2023 and 2022, 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,
	2023		2022
	(Unaudited)
Net income	$	94.2	$	66.0
Unrealized gain (loss) on designated cash flow hedge (1)	(1.2)		0.1
Comprehensive income	93.0		66.1
Comprehensive income attributable to non-controlling interest	36.0		30.8
Comprehensive income attributable to ENLC	$	57.0	$	35.3

____________________________

(1)Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

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, 2022	$	1,306.4	469.0	$	—	$	1,606.3	$	2,912.7
Conversion of unit-based awards for common units, net of units withheld for taxes	(16.8)		2.5	—		—		(16.8)
Unit-based compensation	4.0		—	—		—		4.0
Contributions from non-controlling interests	—		—	—		8.4		8.4
Distributions	(61.7)		—	—		(42.4)		(104.1)
Unrealized loss on designated cash flow hedge (1)	—		—	(1.2)		—		(1.2)
Repurchase of Series C Preferred Units	—		—	—		(3.9)		(3.9)
Common units repurchased	(51.4)		(4.4)	—		—		(51.4)
Net income	58.2		—	—		36.0		94.2
Balance, March 31, 2023	$	1,238.7	467.1	$	(1.2)	$	1,604.4	$	2,841.9

____________________________

(1)Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

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
	$		Units	$		$		$
	(Unaudited)
Balance, December 31, 2021	$	1,325.8	484.3	$	(1.4)	$	1,662.6	$	2,987.0
Conversion of unit-based awards 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.

9

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)

	Three Months Ended March 31,
	2023		2022
	(Unaudited)
Cash flows from operating activities:
Net income	$	94.2	$	66.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	160.4		152.9
Utility credits redeemed	1.4		5.6
Deferred income tax expense	10.8		3.0
(Gain) loss on disposition of assets	(0.4)		5.1
Non-cash unit-based compensation	4.0		6.6
Non-cash loss on derivatives recognized in net income	1.4		17.3
Amortization of debt issuance costs and net discount of senior unsecured notes	1.5		1.3
Loss from unconsolidated affiliate investments	0.1		1.1
Other operating activities	0.3		(1.1)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	101.1		(139.9)
Natural gas and NGLs inventory, prepaid expenses, and other	68.3		(32.8)
Accounts payable, accrued product purchases, and other accrued liabilities	(171.0)		222.6
Net cash provided by operating activities	272.1		307.7
Cash flows from investing activities:
Additions to property and equipment	(100.7)		(60.2)
Contributions to unconsolidated affiliate investments	(49.7)		—
Other investing activities	0.4		1.0
Net cash used in investing activities	(150.0)		(59.2)
Cash flows from financing activities:
Proceeds from borrowings	1,173.0		500.0
Repayments on borrowings	(1,067.4)		(550.0)
Distributions to members	(61.7)		(56.4)
Distributions to non-controlling interests	(42.4)		(34.6)
Payment to redeem mandatorily redeemable non-controlling interest	(10.5)		—
Redemption of Series B Preferred Units	—		(50.5)
Repurchase of Series C Preferred Units	(3.9)		—
Contributions from non-controlling interests	8.4		7.3
Common unit repurchases	(51.4)		(17.0)
Conversion of unit-based awards for common units, net of units withheld for taxes	(16.8)		(4.2)
Other financing activities	0.8		(0.6)
Net cash used in financing activities	(71.9)		(206.0)
Net increase in cash and cash equivalents	50.2		42.5
Cash and cash equivalents, beginning of period	22.6		26.2
Cash and cash equivalents, end of period	$	72.8	$	68.7
Supplemental disclosures of cash flow information:
Cash paid for interest	$	62.2	$	29.4
Non-cash investing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	$	10.4	$	8.5
Non-cash accrual of property and equipment	$	13.4	$	(0.2)

See accompanying notes to consolidated financial statements.

10

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

March 31, 2023

(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.” As of March 31, 2023, GIP, through GIP III Stetson I, L.P. and GIP III Stetson II, L.P, owns 41.3% of the outstanding limited liability company interests in ENLC. In addition to GIP’s equity interests in ENLC, GIP III Stetson I, L.P. maintains control over the Managing Member through its ownership of all of the equity interests in the Managing Member. 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.

As of March 31, 2023, our midstream energy asset network includes approximately 13,600 miles of pipelines, 26 natural gas processing plants with approximately 6.0 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.

11

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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.

(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, 2022 filed with the Commission on February 15, 2023. 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
2023 (remaining)	$	98.0
2024	114.9
2025	101.8
2026	100.7
2027	83.8
Thereafter	1,034.1
Total	$	1,533.3

12

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Redeemable Non-Controlling Interest

During the first quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. At the time of the exercise, we and the interest holder did not agree on the value of the interest and a lawsuit was filed by the interest holder. As part of a settlement effected with the interest holder in January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest for $10.5 million.

(3) Acquisition

Central Oklahoma Acquisition

On December 19, 2022, we completed the Central Oklahoma Acquisition. The acquired assets include approximately 900 miles of lean and rich gas gathering pipeline and two processing plants with 280 MMcf/d of total processing capacity. We completed this acquisition to increase the scale and efficiency of our Central Oklahoma assets.

The following table presents the preliminary fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Consideration
Cash (including working capital payment)	$	100.9
Contingent consideration	1.3
Total consideration	$	102.2
Purchase price allocation (1)
Assets acquired:
Current assets	$	6.0
Property and equipment	97.1
Other assets, net (2)	0.9
Liabilities assumed:
Current liabilities	(1.4)
Other long-term liabilities (2)	(0.4)
Net assets acquired	$	102.2

____________________________

(1)The purchase price allocation was based on preliminary estimates and assumptions, which are subject to change within the measurement period (up to one year from the acquisition date), as we finalize the valuations of the assets acquired and liabilities assumed upon the closing of the acquisition.

(2)“Other assets, net” and “Other long-term liabilities” consist of the right-of-use assets and lease liabilities, respectively, obtained through the Central Oklahoma Acquisition.

13

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Contingent Consideration. The following table represents our change in carrying value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities for the periods presented (in millions):

	Three Months Ended March 31,
	2023		2022
Amarillo Rattler Acquisition contingent consideration
Contingent consideration liability, beginning of period (1)	$	4.2	$	6.9
Change in fair value	0.5		—
Contingent consideration liability, end of period	4.7		6.9
Central Oklahoma Acquisition contingent consideration
Contingent consideration liability, beginning of period (2)	1.3		—
Change in fair value	0.2		—
Contingent consideration liability, end of period	1.5		—
Total contingent consideration
Contingent consideration liability, beginning of period (1)(2)	5.5		6.9
Change in fair value	0.7		—
Contingent consideration liability, end of period	$	6.2	$	6.9

____________________________

(1)The contingent consideration for the Amarillo Rattler Acquisition was recorded on April 30, 2021.

(2)The contingent consideration for the Central Oklahoma Acquisition was recorded on December 19, 2022.

Pro Forma of Acquisitions for the Three Months Ended March 31, 2022

The following unaudited pro forma condensed consolidated financial information (in millions) for the three months ended March 31, 2022 gives effect to the Barnett Shale Acquisition on July 1, 2022 and the Central Oklahoma Acquisition on December 19, 2022 as if each of the acquisitions had occurred on January 1, 2022.

The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

	Three Months Ended March 31, 2022
Pro forma total revenues	$	2,256.9
Pro forma net income	$	75.2

(4) 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, 2023
Customer relationships, beginning of period	$	1,844.8	$	(923.6)	$	921.2
Amortization expense	—		(31.9)		(31.9)
Customer relationships, end of period	$	1,844.8	$	(955.5)	$	889.3

Amortization expense was $31.9 million and $32.8 million for the three months ended March 31, 2023 and 2022, respectively.

14

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

2023 (remaining)	$	95.7
2024	127.6
2025	110.2
2026	106.3
2027	106.3
Thereafter	343.2
Total	$	889.3

(5) Related Party Transactions

(a)    Transactions with Cedar Cove JV

For the three months ended March 31, 2023 and 2022, we recorded cost of sales of $1.5 million and $10.6 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 $1.2 million and $2.5 million at March 31, 2023 and December 31, 2022, respectively.

(b)    Transactions with GIP

General and Administrative Expenses. We did not record any expenses related to transactions with GIP and its affiliates for the three months ended March 31, 2023 and 2022.

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.

15

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(6) Long-Term Debt

As of March 31, 2023 and December 31, 2022, long-term debt consisted of the following (in millions):

	March 31, 2023						December 31, 2022
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Revolving Credit Facility due 2027 (1)	$	505.0	$	—	$	505.0	$	255.0	$	—	$	255.0
AR Facility due 2025 (2)	355.6		—		355.6		500.0		—		500.0
ENLK’s 4.40% Senior unsecured notes due 2024	97.9		—		97.9		97.9		—		97.9
ENLK’s 4.15% Senior unsecured notes due 2025	421.6		(0.1)		421.5		421.6		(0.1)		421.5
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.2)		490.8		491.0		(0.2)		490.8
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
ENLC’s 6.50% Senior unsecured notes due 2030	700.0		—		700.0		700.0		—		700.0
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.1)		444.9		450.0		(5.2)		444.8
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	$	4,869.8	$	(5.7)	4,864.1		$	4,764.2	$	(5.8)	4,758.4
Debt issuance cost (3)					(36.1)						(34.9)
Long-term debt, net of unamortized issuance cost					$	4,828.0					$	4,723.5

____________________________

(1)The effective interest rate was 6.9% and 6.5% at March 31, 2023 and December 31, 2022, respectively.

(2)The effective interest rate was 5.8% and 5.3% at March 31, 2023 and December 31, 2022, respectively.

(3)Net of accumulated amortization of $16.5 million and $15.1 million at March 31, 2023 and December 31, 2022, respectively.

Revolving Credit Facility

The Revolving Credit Facility permits ENLC to borrow up to $1.40 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. There were $505.0 million in outstanding borrowings under the Revolving Credit Facility and $43.6 million in outstanding letters of credit as of March 31, 2023.

At March 31, 2023, we were in compliance with and expect to be in compliance with the financial covenants of the Revolving Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, 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 $589.4 million as of March 31, 2023. As of March 31, 2023, the AR Facility had a borrowing base of $355.6 million and there were $355.6 million in outstanding borrowings under the AR Facility.

At March 31, 2023, 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.

Senior Unsecured Notes

On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of 6.500% senior notes due 2030 (the “Additional Notes”) at 99% of their face value. The Additional Notes were offered as an additional issue of our existing 6.500% senior notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million. Net proceeds of approximately $294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK.

16

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(7) Income Taxes

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

	Three Months Ended March 31,
	2023		2022
Current income tax expense	$	(0.1)	$	(0.2)
Deferred income tax expense	(10.8)		(3.0)
Income tax expense	$	(10.9)	$	(3.2)

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,
	2023		2022
Expected income tax expense based on federal statutory rate	$	(14.5)	$	(8.1)
State income tax expense, net of federal benefit	(1.8)		(1.1)
Unit-based compensation (1)	6.5		(2.0)
Change in valuation allowance	—		7.1
Other	(1.1)		0.9
Income tax expense	$	(10.9)	$	(3.2)

____________________________

(1)Related to book-to-tax differences recorded upon the vesting of unit-based awards.

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, 2023, we had $53.2 million of deferred tax liabilities, net of $731.9 million of deferred tax assets. As of December 31, 2022, we had $42.7 million of deferred tax liabilities, net of $714.1 million of deferred tax assets.

We provide a valuation allowance, if necessary, to reduce deferred tax assets, if all, or some portion, of such assets will more than likely not be realized. We previously established a valuation allowance, primarily related to federal and state tax operating loss carryforwards for which we did not believe a tax benefit was more likely than not to be realized. As of March 31, 2023, we did not record a valuation allowance and management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets.

(8) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of March 31, 2023 and December 31, 2022, there were 54,168,359 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 represented 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we agreed with the holders of the Series B Preferred Units to pay cash in lieu of making a quarterly distribution in-kind of additional Series B Preferred Units (the “PIK Distribution”) through the distribution declared for the fourth quarter of 2022. Beginning with the quarterly distribution declared for the first quarter of 2023, we will resume paying a PIK distribution.

17

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Income is allocated to the Series B Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2023 and 2022 is provided below:

Declaration period	PIK Distribution	Cash distribution (in millions)		Date paid/payable
2023
Fourth Quarter of 2022	—	$	17.3	February 13, 2023
First Quarter of 2023	135,421	$	15.2	May 12, 2023
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022.

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

For tax purposes, holders of Series B Preferred Units are allocated items of gross income from ENLK in respect of each Series B Preferred Unit until the cumulative amount of gross income so allocated equals the cumulative amount of distributions made in respect of such Series B Preferred Unit, but not in excess of such Series B Preferred Unit’s pro rata share of the net income of ENLK for the allocation year (the “Allocation Cap”). Because of the application of the Allocation Cap in 2022 and prior years, as of December 31, 2022, the cumulative amount of distributions made in respect of each Series B Preferred Unit exceeded the cumulative amount of gross income allocated to each Series B Preferred Unit by $5.99 per Series B Preferred Unit (the “Catch-Up Taxable Income Allocation”). As a result, holders of Series B Preferred Units will ultimately be allocated taxable income during future periods equal to the Catch-Up Taxable Income Allocation plus the amount of distributions received in respect of Series B Preferred Units, if ENLK generates positive net income.

b.Series C Preferred Units

Repurchase

In February 2023, we repurchased 4,500 Series C Preferred Units for total consideration of $3.9 million. The repurchase price represented 87% of the preferred units’ par value.

Distributions

Distributions on the Series C Preferred Units accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. Distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to the floating rate of the three-month LIBOR plus a spread of 4.11%. Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period.

As of March 31, 2023 and December 31, 2022, there were 376,500 and 381,000 Series C Preferred Units issued and outstanding, respectively. ENLK made distributions of $8.4 million to the holders of Series C Preferred Units during the three months ended March 31, 2023. There was no distribution activity for the three months ended March 31, 2022. For the distribution period of March 16, 2023 through June 15, 2023, the distribution rate per unit is 9.051%, which is comprised of the three-month LIBOR rate of 4.941% plus a spread of 4.11%. The distribution of $8.5 million is payable on June 15, 2023 to the holders of Series C Preferred Units.

18

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(9) Members’ Equity

a.Common Unit Repurchase Program

In December 2022, the board of directors of the Managing Member (the “Board”) reauthorized our common unit repurchase program for 2023 and set the amount available for repurchases of outstanding common units during 2023 at up to $200.0 million, including repurchases of common units held by GIP. 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.

The following table summarizes our ENLC common unit repurchase activity for the periods presented (in millions, except for unit amounts):

	Three Months Ended March 31,
	2023		2022
Publicly held ENLC common units	2,207,305		2,093,842
ENLC common units held by GIP (1)	2,237,110		—
Total ENLC common units	4,444,415		2,093,842
Aggregate cost for publicly held ENLC common units	$	26.8	$	17.0
Aggregate cost for ENLC common units held by GIP	24.6		—
Total aggregate cost for ENLC common units	$	51.4	$	17.0
Average price paid per publicly held ENLC common unit	$	12.14	$	8.12
Average price paid per ENLC common unit held by GIP (2)	$	11.01	$	—

____________________________

(1)For the three months ended March 31, 2023, the 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 fourth quarter of 2022.

(2)For the three months ended March 31, 2023, the per unit price we paid to GIP was the average per unit price paid by us for publicly held ENLC common units repurchased, less broker commissions, during the fourth quarter of 2022.

Additionally, on May 1, 2023, we repurchased 1,910,877 ENLC common units held by GIP at an aggregate cost of $23.2 million, or an average of $12.12 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended March 31, 2023. The per unit price we paid to GIP was the same as the average per unit price paid by us for publicly held ENLC common units repurchased during the same period, less broker commissions, which were not paid with respect to the GIP units.

19

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

b.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,
	2023		2022
Distributed earnings allocated to:
Common units (1)	$	58.6	$	54.4
Unvested unit-based awards (1)	0.9		1.1
Total distributed earnings	$	59.5	$	55.5
Undistributed loss allocated to:
Common units	$	(1.3)	$	(19.9)
Unvested unit-based awards	—		(0.4)
Total undistributed loss	$	(1.3)	$	(20.3)
Net income attributable to ENLC allocated to:
Common units	$	57.3	$	34.5
Unvested unit-based awards	0.9		0.7
Total net income attributable to ENLC	$	58.2	$	35.2
Net income attributable to ENLC per unit:
Basic	$	0.12	$	0.07
Diluted	$	0.12	$	0.07

____________________________

(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,
	2023	2022
Basic weighted average units outstanding:
Weighted average common units outstanding	468.9	484.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	468.9	484.0
Dilutive effect of unvested unit-based awards	4.4	6.6
Total weighted average diluted common units outstanding	473.3	490.6

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.

20

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Distributions

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2023 and 2022, respectively, is provided below:

Declaration period	Distribution/unit		Date paid/payable
2023
Fourth Quarter of 2022	$	0.12500	February 13, 2023
First Quarter of 2023	$	0.12500	May 12, 2023
2022
Fourth Quarter of 2021	$	0.11250	February 11, 2022
First Quarter of 2022	$	0.11250	May 13, 2022

(10) Investment in Unconsolidated Affiliates

As of March 31, 2023, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):

	Three Months Ended March 31,
	2023		2022
GCF
Contributions	$	6.2	$	—
Equity in loss	$	(1.1)	$	(0.7)
Cedar Cove JV
Distributions	$	(0.1)	$	(0.2)
Equity in loss	$	(0.6)	$	(0.4)
Matterhorn JV
Contributions	$	43.5	$	—
Equity in income	$	1.6	$	—
Total
Contributions	$	49.7	$	—
Distributions	$	(0.1)	$	(0.2)
Equity in loss	$	(0.1)	$	(1.1)

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2023 and December 31, 2022 (in millions):

	March 31, 2023		December 31, 2022
GCF	$	31.4	$	26.3
Cedar Cove JV (1)	(5.1)		(4.4)
Matterhorn JV	109.0		63.9
Total investment in unconsolidated affiliates	$	135.3	$	85.8

____________________________

(1)As of March 31, 2023 and December 31, 2022, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheets.

21

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(11) 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,
	2023		2022
Cost of unit-based compensation charged to operating expense	$	0.9	$	1.6
Cost of unit-based compensation charged to general and administrative expense	3.1		5.0
Total unit-based compensation expense	$	4.0	$	6.6
Amount of related income tax benefit recognized in net income (1)	$	0.9	$	1.6

____________________________

(1)For the three months ended March 31, 2023 and 2022, the amount of related income tax benefit recognized in net income excluded $6.5 million of income tax benefit and $2.0 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of unit-based awards.

b.Restricted Incentive Units

The 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, 2023 is provided below:

	Three Months Ended March 31, 2023
Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Unvested, beginning of period	6,775,186		$	5.89
Granted	1,244,629		10.85
Vested (1)	(2,201,569)		6.07
Forfeited	(55,101)		5.61
Unvested, end of period	5,763,145		$	6.90
Aggregate intrinsic value, end of period (in millions)	$	62.5

____________________________

(1)Vested units included 658,435 ENLC common 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, 2023 and 2022 is provided below (in millions):

	Three Months Ended March 31,
Restricted Incentive Units:	2023		2022
Aggregate intrinsic value of units vested	$	27.1	$	7.6
Fair value of units vested	$	13.4	$	10.7

As of March 31, 2023, there were $25.2 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.

22

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Performance Units

We grant 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, 2023
Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,979,154		$	6.44
Granted	420,128		11.67
Vested (1)	(899,919)		9.03
Non-vested, end of period	2,499,363		$	6.39
Aggregate intrinsic value, end of period (in millions)	$	27.1

____________________________

(1)Vested units included 668,829 ENLC common 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, 2023 and 2022 is provided below (in millions).

	Three Months Ended March 31,
Performance Units:	2023		2022
Aggregate intrinsic value of units vested	$	22.0	$	5.6
Fair value of units vested	$	8.1	$	11.0

As of March 31, 2023, there were $13.8 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 2.0 years.

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

Performance Units:	March 2023
Grant-date fair value	$	10.40
Beginning TSR Price	$	11.67
Risk-free interest rate	3.76		%
Volatility factor	64.00		%

23

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(12) Derivatives

Interest Rate Swaps

In January 2023, we entered into a $400.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, SOFR-based borrowings. Under this arrangement, we pay a fixed interest rate of 3.8565% in exchange for SOFR-based variable interest through February 2026. Assets or liabilities related to this interest rate swap contract are included in the fair value of derivative assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract is recorded net as gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). We designated this interest rate swap as a cash flow hedge in accordance with ASC 815. There is no ineffectiveness related to this hedge.

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

	Three Months Ended March 31,
	2023		2022
Change in fair value of interest rate swaps	$	(1.6)	$	0.1
Tax benefit	0.4		—
Unrealized gain (loss) on designated cash flow hedge	$	(1.2)	$	0.1

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

	March 31, 2023		December 31, 2022
Fair value of derivative assets—current	$	3.1	$	—
Fair value of derivative liabilities—long-term	(4.7)		—
Net fair value of interest rate swaps	$	(1.6)	$	—

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,
	2023		2022
Interest expense (income)	$	(0.5)	$	0.1

We expect to recognize an additional $3.1 million of interest income out of accumulated other comprehensive income (loss) over the next twelve months.

Commodity Derivatives

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

	Three Months Ended March 31,
	2023		2022
Change in fair value of derivatives	$	(1.4)	$	(15.1)
Realized gain (loss) on derivatives	13.3		(16.1)
Gain (loss) on derivative activity	$	11.9	$	(31.2)

24

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

	March 31, 2023		December 31, 2022
Fair value of derivative assets—current	$	65.4	$	68.4
Fair value of derivative assets—long-term	13.6		2.9
Fair value of derivative liabilities—current	(41.1)		(42.9)
Fair value of derivative liabilities—long-term	(13.6)		(2.7)
Net fair value of commodity derivatives	$	24.3	$	25.7

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity derivatives that we held for price risk management purposes and the related physical offsets at March 31, 2023 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028.

Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	MMgals	(144.3)	$	9.1
Natural gas (short contracts)	Swaps and futures	Bbtu	(118.6)	37.4
Natural gas (long contracts)	Swaps and futures	Bbtu	89.3	(21.4)
Crude and condensate (short contracts)	Swaps and futures	MMbbls	(8.9)	4.3
Crude and condensate (long contracts)	Swaps and futures	MMbbls	1.2	(5.1)
Total fair value of commodity derivatives				$	24.3

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. Additionally, we have entered into FCDTCs that allow for netting of futures contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap and futures contracts, the maximum loss on our gross receivable position of $79.0 million as of March 31, 2023 would be reduced to $27.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs and the FCDTCs.

25

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(13) Fair Value Measurements

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

	Level 2
	March 31, 2023		December 31, 2022
Interest rate swaps (1)	$	(1.6)	$	—
Commodity derivatives (2)	$	24.3	$	25.7

____________________________

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

(2)The fair values of commodity derivatives 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, 2023				December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,828.0	$	4,559.2	$	4,723.5	$	4,385.9
Contingent consideration (2)(3)	$	6.2	$	6.2	$	5.5	$	5.5

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $36.1 million and $34.9 million as of March 31, 2023 and December 31, 2022, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable, if at all, 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.

(3)Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable, if at all, between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. 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, 2023 and December 31, 2022 were based on Level 2 inputs from third-party market quotations.

26

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(14) Segment Information

We manage and report our activities primarily according to the geography and nature of activity. We have five reportable segments:

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

•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 Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and adjacent areas;

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

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

27

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. See “Item 2. Management’s Discussion and Analysis of Financial Condition and

Results of Operations—Non-GAAP Financial Measures” for additional information. 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, 2023
Natural gas sales	$	129.3	$	131.8	$	66.8	$	14.5	$	—	$	342.4
NGL sales	0.4		857.9		8.6		(1.0)		—		865.9
Crude oil and condensate sales	186.7		56.6		24.7		—		—		268.0
Product sales	316.4		1,046.3		100.1		13.5		—		1,476.3
NGL sales—related parties	237.5		4.4		118.0		79.5		(439.4)		—
Crude oil and condensate sales—related parties	—		—		—		2.7		(2.7)		—
Product sales—related parties	237.5		4.4		118.0		82.2		(442.1)		—
Gathering and transportation	23.3		20.0		54.8		52.1		—		150.2
Processing	14.0		0.3		35.3		32.1		—		81.7
NGL services	—		27.8		—		—		—		27.8
Crude services	6.0		6.5		4.5		0.2		—		17.2
Other services	1.7		0.4		0.1		0.2		—		2.4
Midstream services	45.0		55.0		94.7		84.6		—		279.3
NGL services—related parties	—		—		—		0.6		(0.6)		—
Midstream services—related parties	—		—		—		0.6		(0.6)		—
Revenue from contracts with customers	598.9		1,105.7		312.8		180.9		(442.7)		1,755.6
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(457.1)		(973.9)		(194.0)		(89.6)		442.7		(1,271.9)
Realized gain (loss) on derivatives	(4.0)		7.2		2.0		8.1		—		13.3
Change in fair value of derivatives	6.3		(9.0)		(1.4)		2.7		—		(1.4)
Adjusted gross margin	144.1		130.0		119.4		102.1		—		495.6
Operating expenses	(48.1)		(33.6)		(24.7)		(26.0)		—		(132.4)
Segment profit	96.0		96.4		94.7		76.1		—		363.2
Depreciation and amortization	(40.0)		(38.3)		(51.9)		(28.8)		(1.4)		(160.4)
Gain on disposition of assets	—		0.1		0.2		0.1		—		0.4
General and administrative	—		—		—		—		(29.5)		(29.5)
Interest expense, net of interest income	—		—		—		—		(68.5)		(68.5)
Loss from unconsolidated affiliate investments	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	$	56.0	$	58.2	$	43.0	$	47.4	$	(99.5)	$	105.1
Capital expenditures	$	56.7	$	12.3	$	25.7	$	18.1	$	1.3	$	114.1

____________________________

(1)Includes related party cost of sales of $1.5 million for the three months ended March 31, 2023.

28

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	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.

29

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as of March 31, 2023 and December 31, 2022 (in millions):

Segment Identifiable Assets:	March 31, 2023		December 31, 2022
Permian	$	2,643.6	$	2,661.4
Louisiana	2,172.4		2,310.7
Oklahoma	2,402.0		2,420.4
North Texas	1,064.8		1,094.6
Corporate (1)	263.6		163.9
Total identifiable assets	$	8,546.4	$	8,651.0

____________________________

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

(15) 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, 2023		December 31, 2022
Natural gas and NGLs inventory	$	70.0	$	147.1
Prepaid expenses and other	24.0		19.5
Other current assets	$	94.0	$	166.6

Other current liabilities:	March 31, 2023		December 31, 2022
Accrued interest	$	63.1	$	57.6
Accrued wages and benefits, including taxes	12.8		38.1
Accrued ad valorem taxes	13.8		32.0
Accrued settlement of mandatorily redeemable non-controlling interest (1)	—		10.5
Capital expenditure accruals	41.0		23.4
Short-term lease liability	27.9		26.2
Operating expense accruals	17.0		18.5
Other	20.3		23.3
Other current liabilities	$	195.9	$	229.6

____________________________

(1)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries.

30

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(16) 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.

One of our subsidiaries, EnLink Energy GP, LLC (“EnLink Energy”), was involved in industry-wide multi-district litigation arising out of Winter Storm Uri, pending in Harris County, Texas, in which multiple individual plaintiffs asserted 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. On January 26, 2023, the court dismissed the claims against the pipeline and other natural gas-related defendants in the multi-district litigation, including EnLink Energy. The court’s order was not appealed and the case is continuing without EnLink Energy and the other natural gas-related defendants. Subsequently, several suits were filed in February 2023 by individual plaintiffs (including one matter in which the plaintiffs seek to certify a class of Texas residents affected by Winter Storm Uri) and the alleged assignee of the claims of individual plaintiffs against 90 natural gas producers, pipelines, marketers, sellers, and traders, including EnLink Gas. All of these matters are currently pending in Harris County, Texas. Three of such suits, including the proposed class action, have been incorporated into the aforementioned industry-wide multi-district litigation. We believe the claims in these matters against EnLink Gas 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.

As of March 31, 2023, our midstream energy asset network includes approximately 13,600 miles of pipelines, 26 natural gas processing plants with approximately 6.0 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 geography and nature of activity. We have five reportable segments:

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

•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 Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and adjacent areas;

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

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, GCF in South Texas, and the Matterhorn JV in West Texas, as well as 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 85% of our adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the three months ended March 31, 2023.

32

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, 2023 and 2022. No other customers represented greater than 10% of our consolidated revenues during the periods presented.

	Three Months Ended March 31,
	2023		2022
Dow Hydrocarbons and Resources LLC	11.4	%	13.9	%
Marathon Petroleum Corporation	20.1	%	16.1	%

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. 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 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.

33

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 building a carbon transportation business in support of CCS activity 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 us with an advantage in building a carbon transportation business and becoming the transporter of choice in the region.

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. Low prices for these commodities could reduce the demand for our services and the volumes in our systems.

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 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 rose especially rapidly in the first half of 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical events, including Russia’s invasion of Ukraine. Since that time, both oil and especially natural gas prices have declined from their peaks during 2022, with natural gas prices declining significantly since the beginning of 2023 and returning to pre-pandemic price levels.

34

The table below shows the range of closing prices for crude oil, NGL, and natural gas during the three months ended March 31, 2023 and 2022.

		Three Months Ended March 31,
		2023			2022
Commodity	Index	Closing Price		Date	Closing Price		Date
Crude oil (high)	NYMEX	$	81.62	January 23, 2023	$	123.70	March 8, 2022
Crude oil (low)	NYMEX	$	66.74	March 17, 2023	$	76.08	January 3, 2022
Crude oil (average) (1)	NYMEX	$	75.99	—	$	95.01	—
NGL (high)	OPIS Napoleonville	$	0.69	January 19, 2023	$	1.12	March 8, 2022
NGL (low)	OPIS Napoleonville	$	0.49	March 16, 2023	$	0.75	January 3, 2022
NGL (average) (1)	OPIS Napoleonville	$	0.61	—	$	0.92	—
Natural gas (high)	Henry Hub Gas Daily	$	4.17	January 4, 2023	$	5.64	March 31, 2022
Natural gas (low)	Henry Hub Gas Daily	$	1.99	March 29, 2023	$	3.72	January 4, 2022
Natural gas (average) (1)	Henry Hub Gas Daily	$	2.74	—	$	4.56	—

____________________________

(1)The average closing price was computed by taking the sum of the closing prices of each trading day divided by the number of trading days during the period presented.

The volatility in commodity prices may cause our adjusted gross margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes.

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. This demand by investors for increased capital discipline from energy companies 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 2022, capital investments by United States oil and natural gas producers have risen, although global capital investments by oil and natural gas producers remain below 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 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. We continue to experience a robust increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity. 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, experienced reduced investment and declines in volumes produced. However, the rise in commodity prices during 2022 led to renewed producer interest in Oklahoma and North Texas which has continued into 2023. However, the recent decline in natural gas prices could cause producer activity to decrease in these areas during the second half of 2023.

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 2022 and has continued into 2023, 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, 2022 filed with the Commission on February 15, 2023.

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Inflation

Inflation in the United States increased significantly in 2022 and has continued during the first quarter of 2023. In addition, in order to reduce the inflation rate, the Federal Reserve increased its target for the federal funds rate (the benchmark for most interest rates) several times in 2022 and 2023. This trend may continue during the remainder of 2023.

To the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods, or other factors; (2) provisions in our contracts that enable us to pass through higher costs to customers; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

Regulatory Developments

Any regulatory changes could 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 Item 1A—Risk Factors—“Environmental, Legal Compliance, and Regulatory Risk” in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the Commission on February 15, 2023.

Other Recent Developments

Organic Growth

Tiger II Processing Plant. In the first half of 2023, we plan to begin moving equipment and facilities associated with the non-operational Cowtown processing plant in North Texas to our Delaware JV operations in the Permian. The relocation is expected to increase the processing capacity of our Permian Basin processing facilities by approximately 150 MMcf/d. We expect to complete the relocation in the second quarter of 2024.

GCF Operations. In January of 2023, we began the process to restart the GCF assets and expect operations to begin in 2024. We will continue to make capital contributions during 2023 associated with the restart of these assets.

Equity

Common Unit Repurchase Program. In the first quarter of 2023, we repurchased 2,207,305 outstanding common units in open market purchases, for an aggregate cost, including commissions, of $26.8 million, or an average of $12.14 per common unit.

GIP Repurchase Agreement. On February 13, 2023, we repurchased 2,237,110 ENLC common units held by GIP for an aggregate cost of $24.6 million, or an average of $11.01 per common unit.

See “Item 1. Financial Statements—Note 9” for more information regarding our common unit repurchases.

Repurchase of Series C Preferred Units. In February 2023, we repurchased 4,500 Series C Preferred Units for total consideration of $3.9 million. The repurchase price represented 87% of the preferred units’ par value.

See “Item 1. Financial Statements—Note 8” for more information regarding the Series C Preferred Units.

Debt

Senior Unsecured Notes Issuance. On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of 6.500% senior notes due 2030 (the “Additional Notes”) at 99% of their face value. The Additional Notes were offered as an additional issue of our existing 6.500% senior notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million. Net proceeds of approximately $294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK.

36

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,
	2023		2022
Total revenues	$	1,767.5	$	2,227.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,271.9)		(1,794.5)
Operating expenses	(132.4)		(120.9)
Depreciation and amortization	(160.4)		(152.9)
Gross margin	202.8		159.4
Operating expenses	132.4		120.9
Depreciation and amortization	160.4		152.9
Adjusted gross margin	$	495.6	$	433.2

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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 derivatives; costs associated with the relocation of processing facilities; accretion expense associated with asset retirement obligations; transaction costs; non-cash expense related to changes in the fair value of contingent consideration; (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,
	2023		2022
Net income	$	94.2	$	66.0
Interest expense, net of interest income	68.5		55.1
Depreciation and amortization	160.4		152.9
Loss from unconsolidated affiliate investments	0.1		1.1
Distributions from unconsolidated affiliate investments	0.1		0.2
(Gain) loss on disposition of assets	(0.4)		5.1
Unit-based compensation	4.0		6.6
Income tax expense	10.9		3.2
Unrealized loss on commodity derivatives	1.4		15.1
Costs associated with the relocation of processing facilities (1)	0.4		11.3
Other (2)	0.3		0.3
Adjusted EBITDA before non-controlling interest	339.9		316.9
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(16.2)		(12.6)
Adjusted EBITDA, net to ENLC	$	323.7	$	304.3

____________________________

(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 in the Oklahoma segment to the Permian segment, where it is operating as the Phantom processing plant. The Phantom processing plant began operations in October 2022.

(2)Includes transaction costs, non-cash expense related to changes in the fair value of contingent consideration, 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); (payment to redeem mandatorily redeemable non-controlling interest); (costs associated with the relocation of processing facilities); non-cash interest (income)/expense; (contributions to investment in unconsolidated affiliates); (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. 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,
	2023		2022
Net cash provided by operating activities	$	272.1	$	307.7
Interest expense (1)	67.0		53.7
Utility credits redeemed (2)	(1.4)		(5.6)
Accruals for settled commodity derivative transactions	—		(2.2)
Distributions from unconsolidated affiliate investment in excess of earnings	0.1		0.2
Costs associated with the relocation of processing facilities (3)	0.4		11.3
Other (4)	0.1		1.7
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	(169.4)		172.7
Accounts payable, accrued product purchases, and other accrued liabilities	171.0		(222.6)
Adjusted EBITDA before non-controlling interest	339.9		316.9
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(16.2)		(12.6)
Adjusted EBITDA, net to ENLC	323.7		304.3
Growth capital expenditures, net to ENLC (6)	(92.7)		(40.5)
Maintenance capital expenditures, net to ENLC (6)	(14.2)		(13.9)
Interest expense, net of interest income	(68.5)		(55.1)
Distributions declared on common units	(58.7)		(55.5)
ENLK preferred unit accrued cash distributions (7)	(23.6)		(23.5)
Payment to redeem mandatorily redeemable non-controlling interest (8)	(10.5)		—
Costs associated with the relocation of processing facilities (3)	(0.4)		(11.3)
Contribution to investment in unconsolidated affiliates	(49.7)		—
Other (9)	0.3		0.4
Free cash flow after distributions	$	5.7	$	104.9

____________________________

(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” on our consolidated balance sheets 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 in the Oklahoma segment to the Permian segment, where it is operating as the Phantom processing plant. The Phantom processing plant began operations in October 2022.

(4)Includes transaction costs, 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 8” 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)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries. See “Item 1. Financial Statements—Note 2” for more information regarding the redemption.

(9)Includes current income tax 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, 2023
Total revenues	$	601.2	$	1,103.9	$	313.4	$	191.7	$	(442.7)	$	1,767.5
Cost of sales, exclusive of operating expenses and depreciation and amortization	(457.1)		(973.9)		(194.0)		(89.6)		442.7		(1,271.9)
Adjusted gross margin	144.1		130.0		119.4		102.1		—		495.6
Operating expenses	(48.1)		(33.6)		(24.7)		(26.0)		—		(132.4)
Segment profit	96.0		96.4		94.7		76.1		—		363.2
Depreciation and amortization	(40.0)		(38.3)		(51.9)		(28.8)		(1.4)		(160.4)
Gross margin	$	56.0	$	58.1	$	42.8	$	47.3	$	(1.4)	$	202.8
	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended March 31, 2022
Total revenues	$	885.0	$	1,512.2	$	383.6	$	242.0	$	(795.1)	$	2,227.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	(766.7)		(1,388.7)		(276.8)		(157.4)		795.1		(1,794.5)
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)
Gross margin	$	36.3	$	55.0	$	34.9	$	34.6	$	(1.4)	$	159.4

	Three Months Ended March 31,
	2023	2022
Midstream Volumes:
Consolidated
Gathering and Transportation (MMbtu/d)	7,172,700	6,209,500
Processing (MMbtu/d)	3,469,600	2,900,100
Crude Oil Handling (Bbls/d)	188,100	190,400
NGL Fractionation (Gals/d)	7,690,000	8,033,900
Brine Disposal (Bbls/d)	3,000	3,000
Permian Segment
Gathering and Transportation (MMbtu/d)	1,683,700	1,347,100
Processing (MMbtu/d)	1,560,700	1,256,300
Crude Oil Handling (Bbls/d)	142,600	150,700
Louisiana Segment
Gathering and Transportation (MMbtu/d)	2,693,500	2,497,700
Crude Oil Handling (Bbls/d)	18,300	15,900
NGL Fractionation (Gals/d)	7,690,000	8,033,900
Brine Disposal (Bbls/d)	3,000	3,000
Oklahoma Segment
Gathering and Transportation (MMbtu/d)	1,178,400	1,000,700
Processing (MMbtu/d)	1,164,300	1,029,500
Crude Oil Handling (Bbls/d)	27,200	23,800
North Texas Segment
Gathering and Transportation (MMbtu/d)	1,617,100	1,364,000
Processing (MMbtu/d)	744,600	614,300

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Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

Revenues and Cost of Sales, Exclusive of Operating Expenses and Depreciation and Amortization.

Our consolidated and segment revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, are from natural gas, NGL, crude oil, and condensate product sales and purchases, midstream services that we perform on those commodities, and derivative activity. Fluctuations in our consolidated and segment revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, reflect in large part changes in commodity prices and volumes. Our adjusted gross margin is not directly affected by the commodity price environment because the commodities that we buy and sell are generally based on the same pricing indices. Both consolidated and segment product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, will fluctuate with market prices; however, the adjusted gross margin related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, fluctuations in these measures from changes in commodity prices may be offset by gains or losses from derivative instruments that we use to manage our exposure to commodity price risk associated with such sales and purchases.

Total revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $460.2 million and $522.6 million, respectively, for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due to the following:

•Product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $567.6 million and $522.6 million, respectively, for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 primarily due to lower commodity prices in 2023.

•Revenues from midstream services increased $64.3 million for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 primarily due to higher volumes in 2023. Of these higher volumes in 2023, $17.5 million was related to contributions from acquisitions completed during 2022.

•Derivative losses decreased $43.1 million for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due to $29.4 million of increased realized gains and $13.7 million of decreased unrealized losses.

Operating Expenses. Operating expenses increased $11.5 million for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 primarily due to $5.1 million of higher utility costs, $4.9 million of increased compressor rentals, $3.4 million of higher materials and supplies expense, and $1.6 million of higher compressor overhaul costs. The increase was partially offset by $4.5 million of decreased construction fees and services.

Depreciation and Amortization. Depreciation and amortization increased $7.5 million for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 primarily due to $5.8 million of depreciation due to changes in estimated useful lives, $3.7 million of depreciation due to acquisitions completed in 2022, and $3.4 million of depreciation due to additional assets placed in service. These increases were partially offset by decreased depreciation of $3.5 million related to assets reaching the end of their useful lives and a $1.9 million decrease due to accelerated depreciation recorded in the first quarter of 2022 related to the relocation of assets to the Phantom processing facility.

Interest Expense, Net of Interest Income. Interest expense, net of interest income, was $68.5 million for the three months ended March 31, 2023 compared to $55.1 million for the three months ended March 31, 2022, an increase of $13.4 million. Interest expense, net of interest income, consisted of the following (in millions):

	Three Months Ended March 31,
	2023		2022
ENLK and ENLC senior notes	$	53.9	$	50.3
Revolving Credit Facility	7.5		2.3
AR Facility	6.2		1.1
Amortization of debt issuance costs and net discount of senior unsecured notes	1.5		1.3
Interest rate swaps - realized	(0.5)		0.1
Other	(0.1)		—
Interest expense, net of interest income	$	68.5	$	55.1

43

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $0.1 million for the three months ended March 31, 2023 compared to a loss of $1.1 million for the three months ended March 31, 2022, a reduction in loss of $1.0 million. The reduction in loss was primarily attributable to income of $1.6 million related to the Matterhorn JV for the three months ended March 31, 2023. The reduction in loss was partially offset by an increase in loss of $0.4 million related to our GCF investment and $0.2 million related to the Cedar Cove JV.

Income Tax Expense. Income tax expense was $10.9 million for the three months ended March 31, 2023 compared to an income tax expense of $3.2 million for the three months ended March 31, 2022. The increase in income tax expense was primarily attributable to the increase in income between periods. See “Item 1. Financial Statements—Note 7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $36.0 million for the three months ended March 31, 2023 compared to net income of $30.8 million for the three months ended March 31, 2022, an increase of $5.2 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 $4.5 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV and a $2.4 million increase in income attributable to the Series C Preferred Units. The increase in income was partially offset by a $0.9 million decrease attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV and a $0.8 million decrease in income attributable to the Series B Preferred Units.

Analysis of Operating Segments

We manage and report our activities primarily according to the geography and nature of activity. We have five reportable segments: Permian segment, Louisiana segment, Oklahoma segment, North Texas segment, and Corporate segment. We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. The GAAP measure most directly comparable to adjusted gross margin and segment profit is gross margin. We also believe that investors benefit from having access to the same financial measures that our management uses to evaluate segment results.

See below for our discussion of segment results for the three months ended March 31, 2023 compared to the three months ended March 31, 2022.

•Permian Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $283.8 million and $309.6 million, respectively, resulting in an increase in adjusted gross margin in the Permian segment of $25.8 million, which was primarily driven by:

•A $34.9 million increase in adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $20.0 million, which was primarily due to higher volumes from existing customers and was partially offset by lower commodity prices. Derivative activity associated with our Permian gas assets increased adjusted gross margin by $14.9 million, which included $0.1 million from decreased realized losses and $14.8 million from increased unrealized gains.

•A $9.1 million decrease in adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, decreased $4.8 million, which was primarily due to lower commodity prices. Derivative activity associated with our Permian crude assets decreased adjusted gross margin by $4.3 million, which included $1.7 million from increased realized losses and $2.6 million from decreased unrealized gains.

◦Operating expenses in the Permian segment increased $2.8 million primarily due to $2.7 million of higher compressor rentals, $2.2 million of higher utilities costs, $1.6 million of higher compressor overhaul costs, $0.7 million of higher labor and benefits costs, and $0.6 million of higher materials and supplies expense. These increases in operating expenses were principally due to an increase in operating activity. The increase was offset by $4.2 million of lower construction fees and services and $1.1 million of lower sales and use tax.

◦Depreciation and amortization in the Permian segment increased $3.3 million primarily due to new assets placed into service.

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•Louisiana Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $408.3 million and $414.8 million, respectively, resulting in an increase in adjusted gross margin in the Louisiana segment of $6.5 million, resulting from:

•A $4.6 million increase in adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $0.2 million, which was primarily due to higher seasonal fees for delivery of normal butane and was partially offset by fluctuations in market prices. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased adjusted gross margin by $4.4 million, which included $3.7 million from increased realized gains and $0.7 million from decreased unrealized losses.

•A $5.7 million increase in adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $1.8 million, which was primarily due to higher transportation volumes and gains on storage activity partially offset by lower processing volumes. Derivative activity associated with our Louisiana gas assets increased adjusted gross margin by $3.9 million, which included $8.0 million from increased realized gains and $4.1 million from increased unrealized losses.

•A $3.8 million decrease in adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $5.9 million, which was primarily due to lower compression fee revenue resulting from the sale of several compressor units and fluctuation in market prices. Derivative activity associated with our ORV crude assets increased adjusted gross margin by $2.1 million from increased realized gains.

◦Operating expenses in the Louisiana segment increased $0.6 million primarily due to higher utility costs.

◦Depreciation and amortization in the Louisiana segment increased $2.8 million primarily due to changes in estimated useful lives of certain non-core assets.

•Oklahoma Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $70.2 million and $82.8 million, respectively, resulting in an increase in adjusted gross margin in the Oklahoma segment of $12.6 million, resulting from:

•A $12.7 million increase in adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $1.4 million, which was primarily due to the Central Oklahoma Acquisition in December 2022 and was partially offset by lower commodity prices. Derivative activity associated with our Oklahoma gas assets increased adjusted gross margin by $11.3 million, which included $5.6 million from increased realized gains and $5.7 million from decreased unrealized losses.

•A $0.1 million decrease in adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $0.2 million, which was primarily due to fluctuation in market prices. Derivative activity associated with our Oklahoma crude assets increased adjusted gross margin by $0.1 million from increased realized gains.

◦Operating expenses in the Oklahoma segment increased $3.7 million primarily due to $2.0 million of higher compressor rentals, $1.5 million of higher ad valorem taxes, $1.1 million of higher utility costs, and $0.6 million of higher materials and supplies expense due to an increase in operating activity. The increase was offset by $2.0 million of lower construction fees and services.

◦Depreciation and amortization in the Oklahoma segment increased $1.0 million primarily due to increases of $2.0 million related to changes in estimated useful lives and $1.0 million related to the Central Oklahoma Acquisition, partially offset by a $1.9 million decrease related to the transfer of equipment to the Phantom processing facility.

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•North Texas Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $50.3 million and $67.8 million, respectively, resulting in an increase in adjusted gross margin in the North Texas segment of $17.5 million. Adjusted gross margin, excluding derivative activity, increased $6.8 million, which was primarily due to the Barnett Shale Acquisition on July 1, 2022 and was partially offset by lower commodity prices. Derivative activity associated with our North Texas segment increased adjusted gross margin by $10.7 million, which included $11.5 million from increased realized gains and $0.8 million from decreased unrealized gains.

◦Operating expenses in the North Texas segment increased $4.4 million primarily due to $2.0 million of higher materials and supplies expense, $1.5 million of higher construction fees and services, $0.7 million of higher ad valorem taxes, $0.6 million of higher labor and benefits costs, and $0.4 million of higher utility costs due to an increase in operating activity and the Barnett Shale Acquisition on July 1, 2022. The increase was offset by $1.0 million of lower sales and use tax.

◦Depreciation and amortization in the North Texas segment increased $0.4 million primarily due to $2.7 million related to the Barnett Shale Acquisition on July 1, 2022 and $1.0 million related to changes in useful lives, partially offset by a $3.5 million decrease due to asset reaching the end of their depreciable lives.

•Corporate Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, each increased $352.4 million. The corporate segment includes offsetting eliminations related to intercompany revenues and cost of sales, exclusive of operating expenses and depreciation and amortization.

◦Depreciation and amortization in the Corporate segment was $1.4 million for both periods.

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, 2022 filed with the Commission on February 15, 2023.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $272.1 million for the three months ended March 31, 2023 compared to $307.7 million for the three months ended March 31, 2022. 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,
	2023		2022
Operating cash flows before working capital	$	273.7	$	257.8
Changes in working capital	(1.6)		49.9

Operating cash flows before changes in working capital increased $15.9 million for the three months ended March 31, 2023 compared to the three months ended March 31, 2022. The primary contributor to the increase in operating cash flows before working capital was as follows:

•Gross margin, excluding depreciation and amortization, non-cash commodity derivative activity, utility credits redeemed or earned, and unit-based compensation, increased $30.1 million. The increase in gross margin is due to a $46.5 million increase in adjusted gross margin, excluding non-cash commodity derivative activity, which was partially offset by a $16.4 million increase in operating expenses, excluding utility credits redeemed or earned and unit-based compensation. For more information regarding the changes in gross margin for the three months ended March 31, 2023 compared to the three months ended March 31, 2022, see “Results of Operations.”

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The increase in operating cash flows were partially offset by the following:

•Interest expense, net of interest income, excluding amortization of debt issue costs and net discounts, increased $13.2 million.

•General and administrative expenses, excluding unit-based compensation, increased $2.4 million.

The changes in working capital for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 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 $150.0 million for the three months ended March 31, 2023 compared to $59.2 million for the three months ended March 31, 2022. Our primary investing activities consisted of the following (in millions):

	Three Months Ended March 31,
	2023		2022
Additions to property and equipment (1)	$	(100.7)	$	(60.2)
Contributions to unconsolidated affiliate investments (2)	(49.7)		—

____________________________

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

(2)Represents contributions to the Matterhorn JV and GCF. See “Item 1. Financial Statements—Note 10” for more information regarding the contributions to unconsolidated affiliate investments.

Cash Flows from Financing Activities. Net cash used in financing activities was $71.9 million for the three months ended March 31, 2023 compared to $206.0 million for the three months ended March 31, 2022. Our primary financing activities consisted of the following (in millions):

	Three Months Ended March 31,
	2023		2022
Net repayments on the AR Facility (1)	$	(144.4)	$	(35.0)
Net borrowings (repayments) on the Revolving Credit Facility (1)	250.0		(15.0)
Distributions to members	(61.7)		(56.4)
Distributions to Series B Preferred Unitholders (2)	(17.3)		(18.6)
Distributions to Series C Preferred Unitholders (2)	(8.4)		—
Distributions to joint venture partners (3)	(16.7)		(16.0)
Payment to redeem mandatorily redeemable non-controlling interest (4)	(10.5)		—
Redemption of Series B Preferred Units (2)	—		(50.5)
Repurchase of Series C Preferred Units (2)	(3.9)		—
Contributions from non-controlling interests (5)	8.4		7.3
Common unit repurchases (6)	(51.4)		(17.0)
Conversion of unit-based awards for common units, net of units withheld for taxes	(16.8)		(4.2)

____________________________

(1)See “Item 1. Financial Statements—Note 6” for more information regarding the AR Facility and the Revolving Credit Facility.

(2)See “Item 1. Financial Statements—Note 8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and information on the partial redemption of the Series B Preferred Units and the repurchase of the Series C Preferred Units.

(3)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.

(4)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries. See “Item 1. Financial Statements—Note 2” for more information regarding the redemption.

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

(6)See “Item 1. Financial Statements—Note 9” for more information regarding our common unit repurchase program.

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Capital Requirements

As of March 31, 2023, the following table summarizes our expected remaining capital requirements for 2023 (in millions):

Capital expenditures, net to ENLC (1)	$	313
Operating expenses associated with the relocation of processing facilities, net to ENLC (2)	15
Contributions to unconsolidated affiliate investments (3)	25
Total	$	353

____________________________

(1)Excludes capital expenditures that are 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 the equipment and facilities associated with the non-operational Cowtown processing plant in North Texas to our Delaware JV operations in the Permian, where it is expected to operate as the Tiger II processing plant. These costs exclude amounts that will be contributed by other entities and relate to the non-controlling interest share of our consolidated entities.

(3)Includes contributions made to our GCF investment and the Matterhorn JV.

Our primary remaining capital projects for 2023 include the relocation of the Cowtown processing plant, CCS-related initiatives, the restart of the GCF assets, contributions to unconsolidated affiliate investments, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining 2023 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, to make contributions to unconsolidated affiliate investments, 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, 2023.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of March 31, 2023 is as follows (in millions):

	Payments Due by Period
	Total		Remainder 2023		2024		2025		2026		2027		Thereafter
ENLC’s & ENLK’s senior unsecured notes	$	4,009.2	$	—	$	97.9	$	421.6	$	491.0	$	—	$	2,998.7
Revolving Credit Facility (1)	505.0		—		—		—		—		505.0		—
AR Facility (2)	355.6		—		—		355.6		—		—		—
Acquisition contingent consideration (3)	6.2		—		0.9		0.4		4.6		0.3		—
Interest payable on fixed long-term debt obligations	2,390.0		166.9		213.5		202.6		193.8		170.0		1,443.2
Operating lease obligations	122.4		24.1		22.3		16.1		9.2		8.2		42.5
Purchase obligations	8.7		8.7		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (4)	970.0		54.7		81.9		113.1		100.0		87.9		532.4
Total contractual obligations	$	8,367.1	$	254.4	$	416.5	$	1,109.4	$	798.6	$	771.4	$	5,016.8

____________________________

(1)The Revolving Credit Facility permits us to borrow up to $1.40 billion on a revolving credit basis and will mature on June 3, 2027.

(2)The AR Facility will terminate on August 1, 2025.

(3)The estimated fair value of the contingent consideration for the Amarillo Rattler Acquisition and the Central Oklahoma Acquisition 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 13” for additional information.

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

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 Revolving Credit Facility and the AR Facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Revolving Credit Facility and the AR Facility, which vary from time to time.

Our contractual cash obligations for the remainder of 2023 are expected to be funded from cash flows generated from our operations.

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Indebtedness

Revolving Credit Facility. As of March 31, 2023, there were $505.0 million in outstanding borrowings and $43.6 million in outstanding letters of credit under the Revolving Credit Facility.

AR Facility. As of March 31, 2023, the AR Facility had a borrowing base of $355.6 million and there were $355.6 million in outstanding borrowings under the AR Facility. In connection with the AR Facility, certain subsidiaries of ENLC sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. The SPV’s assets are not available to satisfy the obligations of ENLC or any of its affiliates.

Senior Unsecured Notes. As of March 31, 2023, we had $4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047 and there were no meaningful near-term senior unsecured note maturities. On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of 6.500% senior notes due 2030 (the “Additional Notes”) at 99% of their face value. The Additional Notes were offered as an additional issue of our existing 6.500% senior notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million.

Guarantees. The amounts outstanding on our senior unsecured notes and the Revolving Credit Facility are guaranteed in full by our subsidiary ENLK, including 105% of any letters of credit outstanding under the Revolving 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 Revolving 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, 2023, 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 6” for more information on our outstanding debt.

Inflation

Inflation in the United States increased significantly in 2022 and has continued during the first quarter of 2023. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments Affecting Industry Conditions and Our Business—Inflation” for more information.

Recent Accounting Pronouncements

We have reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2023 and have determined that none had a material impact to our consolidated financial statements.

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Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report on Form 10-Q 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 future results and growth of our CCS business, when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, cost savings or operational, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of 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) 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, (b) 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, (c) 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, (d) the dependence on key customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (e) developments that materially and adversely affect our key customers or other customers, (f) adverse developments in the midstream business that may reduce our ability to make distributions, (g) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (h) decreases in the volumes that we gather, process, fractionate, or transport, (i) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (j) our ability to receive or renew required permits and other approvals, (k) 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, (l) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (m) changes in the availability and cost of capital, (n) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (o) 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, (p) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (q) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (r) impairments to goodwill, long-lived assets and equity method investments, (s) construction risks in our major development projects, (t) challenges we may face in or in connection with our strategy to enter into new lines of business related to the energy transition, (u) the impact of the coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) and similar pandemics, (v) our ability to effectively integrate and manage assets we acquire through acquisitions, and (w) 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 “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the Commission on February 15, 2023, 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.

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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 derivative activities to separate entities, which may not be as creditworthy as the current counterparties. The legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Commodity Price Risk

We are also subject to direct risks due to fluctuations in commodity prices. While approximately 85% of our adjusted gross margin for the three months ended March 31, 2023 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. For more information regarding our main types of contractual arrangements, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the Commission on February 15, 2023.

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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Commodity derivatives 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, crude, and condensate.

The following table sets forth information related to derivative instruments outstanding at March 31, 2023.

Period	Underlying	Notional Volume (net position)	Reference Price	Price Range	Net Fair Value (Asset/(Liability) (In Millions)
April 2023 - May 2023	Ethane	(20.0) MMgals	OPIS Mt Belvieu	$0.23 - $0.23/Gal	$	0.3
April 2023 - March 2024	Propane	(110.9) MMgals	OPIS Mt Belvieu	$0.79 - $1.04/Gal	8.2
April 2023 - December 2023	Normal Butane	(11.3) MMgals	OPIS Mt Belvieu	$0.96 - $1.01/Gal	0.5
April 2023 - April 2023	Natural Gasoline	(2.1) MMgals	OPIS Mt Belvieu	$1.55 - $1.56/Gal	0.1
April 2023 - January 2028	Natural Gas	(17.0) Bbtu	NYMEX	$2.19 - $6.19/MMbtu	24.6
April 2023 - March 2024	Natural Gas	(12.1) Bbtu	Waha basis differential	($3.02) - ($0.81)/MMbtu	(8.6)
April 2023 - April 2023	Natural Gas	(0.1) Bbtu	Henry Hub Gas Daily	$1.98 - $1.98/MMbtu	—
April 2023 - April 2023	Natural Gas	(0.1) Bbtu	NGPL TEXOK Gas Daily	$1.73 - $1.73/MMbtu	—
May 2023 - January 2024	Crude & Condensate	(0.5) MMbbls	NYMEX WTI	$66.33 - $86.23/Bbl	(2.7)
January 2024 - December 2025	Crude & Condensate	(7.2) MMbbls	WTI-Midland and Houston basis differential	$0.70 - $0.90/Bbl	1.9
Total fair value of commodity derivatives					$	24.3

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, 2023, our outstanding commodity derivative instruments had a net fair value asset of $24.3 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 $19.8 million in the net fair value of these contracts as of March 31, 2023. 

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Interest Rate Risk

We are exposed to interest rate risk on the Revolving Credit Facility and the AR Facility. Amounts drawn on the Revolving Credit Facility and the AR Facility bear interest at rates based on SOFR. At March 31, 2023, we had $505.0 million in outstanding borrowings under the Revolving Credit Facility and $355.6 million in outstanding borrowings under the AR Facility.

In January 2023, we entered into a $400.0 million interest rate swap to reduce the variability of cash outflows associated with interest payments related to our long-term debt with variable interest rates. This swap has been designated as a cash flow hedge. See “Item 1. Financial Statements—Note 12” for more information on our outstanding derivatives.

A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $5.1 million and $3.6 million for the Revolving Credit Facility and the AR Facility, respectively. This change in interest expense would be partially offset by a $4.0 million change in the opposite direction due to our open interest rate swap hedge.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028, 2029, and 2030 as these are fixed-rate obligations. As of March 31, 2023, the estimated fair value of the senior unsecured notes was approximately $3,698.6 million, based on the market prices of ENLK’s and our publicly traded debt at March 31, 2023. 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 $217.8 million decrease in fair value of the senior unsecured notes at March 31, 2023. See “Item 1. Financial Statements—Note 6” for more information on our outstanding indebtedness.

Beginning with the interest period which commenced on December 15, 2022, distributions on ENLK’s Series C Preferred Units are based on a floating rate tied to LIBOR (or an alternative rate to be established) 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. See “Item 1. Financial Statements—Note 8” for more information regarding distributions with respect to the Series C Preferred Units.

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, 2023), 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, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

54

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 16, “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, 2022 filed with the Commission on February 15, 2023.

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

During the three months ended March 31, 2023, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of unit-based awards and we repurchased common units in open market transactions and from GIP 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, 2023 to January 31, 2023	1,359,821	$	12.56	703,587	$	191.0
February 1, 2023 to February 28, 2023	3,503,904	11.61		2,835,075	$	158.8
March 1, 2023 to March 31, 2023	907,954	11.35		905,753	$	148.6
Total	5,771,679	$	11.79	4,444,415

____________________________

(1)The total number of units purchased shown in the table includes 1,327,264 ENLC common units received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)In December 2022, the Board reauthorized our common unit repurchase program for 2023 and set the amount available for repurchases of outstanding common units during 2023 at up to $200.0 million. 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. For more information regarding common units repurchased from public unitholders and our repurchase of common units held by GIP, see “Item 1. Financial Statements—Note 9.”

55

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).
4.1	—	Indenture, dated as of August 31, 2022, by and among EnLink Midstream, LLC, as issuer, EnLink Midstream Partners, LP, as guarantor, and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to EnLink Midstream, LLC’s Current Report on Form 8-K, filed on August 31, 2022, file No. 001-36336).
10.1†*	—	Form of 2023 Performance Unit Agreement made under the 2014 Plan.
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, 2022, filed with the Commission on February 15, 2023, 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, 2023, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of March 31, 2023 and December 31, 2022, (ii) Consolidated Statements of Operations for the three months ended March 31, 2023 and 2022, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended March 31, 2023 and 2022, (iv) Consolidated Statements of Cash Flows for the three months ended March 31, 2023 and 2022, and (v) the Notes to Consolidated Financial Statements.
104 *	—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

____________________________

*    Filed herewith.

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

56

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 3, 2023

57

EX-10.1

Exhibit 10.1

PERFORMANCE UNIT AGREEMENT

THIS PERFORMANCE UNIT AGREEMENT (this “Agreement”) is entered into by and between EnLink Midstream, LLC, a Delaware limited liability company (the “Company”), and _____________ (“Participant”) as of the Grant Date (as defined below).

WITNESSETH:

WHEREAS, the EnLink Midstream, LLC 2014 Long-Term Incentive Plan was adopted by the Company, effective February 5, 2014 (as amended, the “Plan”), for the benefit of certain employees and consultants of the Company or its Affiliates (as defined in the Plan), and non-employee directors of EnLink Manager (as defined in the Plan), the managing member of the Company; and

WHEREAS, the Committee (as defined in the Plan) is responsible for granting Awards (as defined in the Plan) in accordance with the Plan; and

WHEREAS, Participant is eligible to participate in the Plan and the Committee has authorized the grant to Participant of the “Subject Award” (as defined in Section 2 of this Agreement), which shall be subject to certain restrictions pursuant to the Plan and upon the terms set forth herein.

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

1.    Definitions. Capitalized terms used herein and not otherwise defined herein shall have the meaning ascribed to them in the Plan.

“Cause” shall have the meaning ascribed to such term (i) in the Severance Agreement (which meaning shall include any procedural aspects for establishing a termination for Cause pursuant to the Severance Agreement), or (ii) in the Plan if no Severance Agreement exists.

“CF Tranche RIUs” means the Tranche RIUs with a Performance Goal based on Cash Flow.

“Change in Control” shall have the meaning ascribed to such term (i) in the Change in Control Agreement (which meaning shall include any procedural aspects for establishing a termination for Change in Control pursuant to the Change in Control Agreement), or (ii) in the Plan if no Change in Control Agreement exists.

“Change in Control Agreement” means (i) the Change in Control Agreement, as amended, if any, between Participant and EnLink Midstream Operating, LP, a Delaware limited partnership (or its successor), that is in effect as of the Grant Date or (ii) if Participant is not a party to a Change in Control Agreement contemplated in clause (i) of this definition, the most recent form of change in control agreement that has been included as an exhibit to the Company’s filings with the U.S. Securities and Exchange Commission (the “SEC”) prior to the Grant Date.

“Company Group” means the Company, EnLink Midstream Manager, LLC, EnLink Midstream Partners, LP, EnLink Midstream GP, LLC, EnLink Midstream Operating, LP and each of their respective direct or indirect subsidiaries.

“Early Retirement” means (i) Participant’s Retirement on or after his or her attainment of age 55, and (ii) immediately prior to such Retirement, the number of such Participant’s years of continuous service with the Company or its Affiliates (including continuous service with a predecessor employer that is taken into account pursuant to an acquisition or other transaction agreement) equals or exceeds 10 years. For the avoidance of doubt, a Normal Retirement shall be deemed to occur, if at all, to the extent Participant meets the applicable age and service requirements to be eligible for both Early Retirement and Normal Retirement.

“End Date” means the date on which the Cumulative Performance Period ends.

Exhibit 10.1

“Good Reason” (i) shall have the meaning ascribed to such term in the Severance Agreement (which meaning shall include any procedural aspects for establishing a termination for Good Reason pursuant to the Severance Agreement), or, (ii) if no Severance Agreement exists, then shall mean any of the following, without Participant’s consent: (w) a material reduction in Participant’s base annual salary; (x) a material adverse change in Participant’s authority, duties, or responsibilities (other than temporarily while Participant is physically or mentally incapacitated or as required by applicable law); (y) a material breach by the Company of any material provision of this Agreement (or by a member of the Company Group of any material provision of any other written agreement between Participant and any member of the Company regarding his or her services thereto); or (z) the Company requires that Participant move his or her principal place of service to a location that is thirty (30) or more miles from his or her current principal place of service and the new location is farther from his or her primary residence. Participant may not terminate his or her employment for “Good Reason” unless (A) Participant gives the Company written notice of the event within thirty (30) days of the occurrence of the event, (B) the Company fails to remedy the event within thirty (30) days following its receipt of the notice, and (C) Participant terminates his or her service with the Company and its Affiliates within sixty (60) days following the Company’s receipt of written notice.

“Grant Date” means [●].

“Intermediate Retirement” means (i) Participant’s Retirement on or after his or her attainment of age 60, and (ii) immediately prior to such Retirement, the number of such Participant’s years of continuous service with the Company or its Affiliates (including continuous service with a predecessor employer that is taken into account pursuant to an acquisition or other transaction agreement) is less than five years.

“Normal Retirement” means (i) Participant’s Retirement on or after his or her attainment of age 60, and (ii) immediately prior to such Retirement, the number of such Participant’s years of continuous service with the Company or its Affiliates (including continuous service with a predecessor employer that is taken into account pursuant to an acquisition or other transaction agreement) equals or exceeds five years; provided, however, that, a Normal Retirement will not occur if Participant’s Retirement occurs prior to the one-year anniversary of the commencement of the First Performance Period unless the Committee approves the same in its sole discretion. For the avoidance of doubt, a Normal Retirement shall be deemed to occur, if at all, to the extent Participant meets the applicable age and service requirements to be eligible for both Early Retirement and Normal Retirement.

“Performance Goal” means, with respect to a Subject Tranche, the applicable Performance Goal as set forth in Schedule B to this Agreement.

“Performance Period” means the applicable measurement period under this Agreement for purposes of determining attainment of the Performance Goal with respect to a Subject Tranche.

Under this Agreement, the following four Performance Periods shall apply to the Performance Goal based on TSR:

•The “First Performance Period” shall comprise the period commencing on January 1, 2023 and ending on December 31st of that same year;

•The “Second Performance Period” shall comprise the period commencing on January 1, 2024 and ending on December 31st of that same year;

•The “Third Performance Period” shall comprise the period commencing on January 31, 2025 and ending on December 31st of that same year; and

•The “Cumulative Performance Period” shall comprise the period commencing on January 1, 2023 and ending on December 31, 2025.

Under this Agreement, the following three Performance Periods shall apply to the Performance Goal based on Cash Flow:

•The First Performance Period;

•The Second Performance Period; and

•The Third Performance Period.

Exhibit 10.1

“Prorated Amount” means a number equal to the total number of Certified RIUs multiplied by a fraction (i) the numerator of which is the number of days that elapse from the commencement of the applicable Performance Period to, as applicable, the date of a Qualifying Termination or the date of Retirement (it being understood that once the numerator equals or exceeds the number of days in the applicable Performance Period, the Certified RIUs for such Performance Period shall be considered to have been fully earned and there shall not be any increase to such Certified RIUs and (ii) if the numerator is zero, because the date of the Qualifying Termination or Retirement is prior to the initial date of the applicable Performance Period, no Certified RIUs for such Performance Period shall be earned), and (ii) the denominator of which is the total number of days in the applicable Performance Period; provided, however, that for the Cumulative Performance Period, such proration calculation shall be done on a year-by-year basis (but shall reflect the Cumulative Performance Period attainment).

“Qualifying Disability” means, as applicable, the earliest to occur of: (i) Participant’s “disability” within the meaning of Treas. Reg. Section 1.409A-3(i)(4), or (ii) Participant’s Separation from Service that is incurred after Participant has become disabled and qualified to receive benefits under the Company’s long-term disability plan.

“Qualifying Termination” means Participant’s Separation from Service with the Company and its Affiliates due to (i) an involuntary termination of Participant by the Company or its Affiliates for reasons other than Cause or Qualifying Disability or (ii) a termination by Participant for Good Reason.

“Retirement” means Participant’s Separation from Service with the Company and its Affiliates for reasons other than Cause due to his or her retirement; provided that (i) Participant provides the Company with at least 90 days’ advance written notice of such retirement, which notice may be waived by the Chief Executive Officer of EnLink Manager and (ii) such retirement is otherwise approved by the Chief Executive Officer of EnLink Manager in his or her sole discretion. Notwithstanding any provision herein to the contrary, Participant will not be eligible to receive any benefits hereunder with respect to Early Retirement or Intermediate Retirement, if such Participant is eligible to receive benefits with respect to Normal Retirement under any other Award.

“Retirement Conditions” means, with respect to Participant’s Retirement, (i) Participant’s compliance with Schedule D through the date of his or her Retirement and (ii) solely if requested by the Company in its sole discretion, Participant shall deliver to the Company, prior to his or her Retirement, an acknowledgment of his or her obligations to comply with Schedule D (it being understood that Participant agrees to the terms and conditions set forth in Schedule D if he or she engages in Early Retirement, Intermediate Retirement, or Normal Retirement regardless of whether he or she delivers any such acknowledgment).

“Separation from Service” shall have the meaning ascribed to such term in the guidance issued under Section 409A of the Code.

“Severance Agreement” means (i) the Severance Agreement, as amended, if any, between Participant and EnLink Midstream Operating, LP, a Delaware limited partnership (or its successor), that is in effect as of the Grant Date or (ii) if Participant is not a party to a Severance Agreement contemplated in clause (i) of this definition, the most recent form of severance agreement that has been included as an exhibit to the Company’s filings with the SEC prior to the Grant Date.

“Subject Tranche” means, as further specified in Schedule A, the portion of the Subject Award (i.e., a designated number of Restricted Incentive Units) that relates to a particular Performance Period and particular Performance Goal.

“TrancheRIUs” means the Restricted Incentive Units that comprise a Subject Tranche.

“TrancheValuation Date” means, with respect to a Subject Tranche, the last day of the Performance Period applicable to the Subject Tranche.

“TSR Tranche RIUs” means the Tranche RIUs with a Performance Goal based on TSR.

2.    Performance Unit Award. On the terms and conditions and subject to the restrictions, including forfeiture, hereinafter set forth, the Company hereby grants to Participant, and Participant hereby accepts, an award

Exhibit 10.1

of [●] Restricted Incentive Units (the “Subject Award”). The Restricted Incentive Units granted hereunder shall be evidenced by the Committee in a book entry or in such other manner as the Committee may determine.

3.    Vesting; Forfeiture.

(a)    In General. The number of Tranche RIUs, if any, that are eligible for vesting as Certified RIUs hereunder shall be based on the Committee’s determination of attainment and associated certification of the applicable Performance Goal, in each case, made in accordance with this Section 3, Schedule B, and Section 4 below. The Committee shall make Performance Goal attainment and certification determinations separately with respect to each Subject Tranche. If at least a “Threshold” performance level (“Qualifying Performance”) is attained and certified, then the applicable number of Tranche RIUs determined under Schedule B and Section 4 below (the “Certified RIUs”) shall vest and Units applicable to such Certified RIUs shall be paid out to Participant in accordance with Section 4 below so long as Participant remains in the continuous service of the Company or its Affiliates until the earlier of (i) the End Date or (ii) the date on which the earliest event occurs in accordance with and pursuant to Section 3(c) or Section 3(d) below whereby the relevant Certified RIUs or Tranche RIUs vest or expressly remain eligible for vesting. For the avoidance of doubt: (x) if a “Below Threshold” performance level is attained and certified, then no Certified RIUs shall relate to the Tranche RIUs and all such Tranche RIUs shall be forfeited; (y) if at least Qualifying Performance is attained and certified, but such performance does not equal or exceed the “Target” performance level pursuant to Schedule B, then the number of Tranche RIUs that exceeds the applicable number of the Certified RIUs shall be forfeited; and (z) if at least Qualifying Performance is attained and certified, but the Certified RIUs are adjusted for the Prorated Amount pursuant to Section 3(c) below, then the number of Tranche RIUs, if any, that exceeds the applicable number of the Certified RIUs, as adjusted for the Prorated Amount, shall be forfeited. All forfeitures under this Agreement shall be at no cost to the Company or Participant.

(b)    Separation from Service in General. Except as otherwise provided in Section 3(c) below, if Participant experiences a Separation from Service with the Company and its Affiliates prior to the End Date, then he or she will forfeit the Subject Award.

(c)    Special Vesting/Forfeiture Conditions. Tranche RIUs and Certified RIUs, if any, shall be subject to the following vesting and forfeiture conditions, which shall apply in connection with a Qualifying Termination, Retirement, Change in Control, Participant’s death, or Qualifying Disability that occurs at a time when there are no grounds in existence for the involuntary termination of Participant (in good faith) by the Company or its Affiliates for Cause:

(i)    General. Except as otherwise provided in this Section 3(c), if a Qualifying Termination, an Early Retirement, an Intermediate Retirement, or a Normal Retirement occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall remain eligible for vesting or vest, if at all, pursuant to clause (x), (y), or (z) below and subclauses (1) or (2) thereunder as follows:

(x)    Qualifying Termination:

(1)    If such a Qualifying Termination occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then such Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such Qualifying Termination.

(2)    If such a Qualifying Termination occurs prior to a given Tranche Valuation Date, then the applicable Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such Tranche RIUs shall be adjusted for the Prorated Amount.

(y)    Early Retirement or Intermediate Retirement:

(1)    If such an Early Retirement or Intermediate Retirement occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then, subject

Exhibit 10.1

to Participant satisfying the Retirement Conditions, such Certified RIUs shall vest(without adjustment for the Prorated Amount) as of the date of such Early Retirement or Intermediate Retirement, as applicable.

(2)    If such an Early Retirement or Intermediate Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, the applicable Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such Tranche RIUs shall be adjusted for the Prorated Amount.

(z)    Normal Retirement:

(1)    If such a Normal Retirement occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then, subject to Participant satisfying the Retirement Conditions, such Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such Normal Retirement.

(2)    If such a Normal Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, such Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount).

(ii)    Double Trigger - Advance/Concurrent Change in Control. If a Change in Control occurs while the Subject Award is outstanding and, on or after such Change in Control, a Qualifying Termination, an Early Retirement, an Intermediate Retirement, or a Normal Retirement occurs during a Performance Period, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall remain eligible for vesting or vest, if at all, pursuant to clause (x) or (y) as follows:

(x)    Qualifying Termination: If such a Qualifying Termination occurs prior to a given Tranche Valuation Date, then (A) the relevant TSR Tranche RIUs shall remain eligible for vesting subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount) and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Qualifying Termination. For the avoidance of doubt, such a Qualifying Termination that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(x)(1) above or Section 3(d) below, as applicable.

(y)    Early Retirement, Intermediate Retirement, or Normal Retirement: If such an Early Retirement, an Intermediate Retirement, or a Normal Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, (A) the relevant TSR Tranche RIUs shall remain eligible for vesting subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount) and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable. For the avoidance of doubt, each of such an Early Retirement, an Intermediate Retirement, or a Normal Retirement that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(y)(1) above, 3(c)(i)(z)(1) above, or Section 3(d) below, as applicable.

(iii)    Double Trigger – Subsequent Change in Control. If, subsequent to the occurrence of a Qualifying Termination, an Early Retirement, an Intermediate Retirement, or a Normal Retirement during a Performance Period, a Change in Control occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall remain eligible for vesting or vest, if at all, pursuant to clause (x), (y), or (z) as follows:

(x)    Qualifying Termination: If such a Qualifying Termination occurs prior to a given Tranche Valuation Date, then (A) the relevant TSR Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such TSR Tranche RIUs shall be adjusted for the Prorated Amount and (B) the relevant CF Tranche RIUs shall be deemed to

Exhibit 10.1

vest as Certified RIUs at the “Target” performance level, as adjusted for the Prorated Amount, as of the date of such Change in Control. For the avoidance of doubt, such a Qualifying Termination that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(x)(1) above or Section 3(d) below, as applicable.

(y)    Early Retirement or Intermediate Retirement: If such an Early Retirement or Intermediate Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, (A) the relevant TSR Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such TSR Tranche RIUs shall be adjusted for the Prorated Amount and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level, as adjusted for the Prorated Amount, as of the date of such Change in Control. For the avoidance of doubt, such an Early Retirement or Intermediate Retirement that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(y)(1) above or Section 3(d) below, as applicable.

(z)    Normal Retirement: If such a Normal Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, (A) the relevant TSR Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount) and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Change in Control. For the avoidance of doubt, such a Normal Retirement that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(z)(1) above or Section 3(d) below, as applicable.

(iv)    Death. If Participant’s death occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall vest, if at all, pursuant to clause (x) or (y) as follows:

(x)    If such a death occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then the relevant Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such death.

(y)    If such a death occurs prior to a given Tranche Valuation Date, then the relevant Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such death.

(v)    Disability. If the Participant’s Qualifying Disability occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall vest, if at all, pursuant to clause (x) or (y) as follows:

(x)    If such Qualifying Disability occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then the relevant Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such Qualifying Disability.

(y)    If such Qualifying Disability occurs prior to a given Tranche Valuation Date, then the relevant Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Qualifying Disability.

(vi)    Section 409A Considerations.

(x)    Change in Control. To the extent that the vesting under Section 3(c)(iii) or Section 3(d) relates to any Subject Tranche that is subject to Section 409A of the Code (a “409A Subject Tranche”), such vesting shall occur only if the applicable Change in Control constitutes “change in the ownership or effective control” of the Company within the meaning of Treas. Reg. Section 1.409A-3(i)(5). If such Change in Control does not constitute such a “change in the ownership or effective control” of the Company, the Tranche RIUs with respect to such 409A Subject Tranche shall remain eligible for vesting in accordance with the other provisions of this Section 3, as applicable.

Exhibit 10.1

(y)    Qualifying Disability. To the extent that the vesting under Section 3(c)(vi) relates to any 409A Subject Tranche, (A) such vesting shall occur only if Participant incurs a “disability” within the meaning of Treas. Reg. Section 1.409A-3(i)(4), or (B) if clause (A) is not applicable, such vesting of the Certified RIUs described in Section 3(c)(vi) shall be dependent on Participant incurring a Separation from Service in connection with his or her Qualifying Disability. In such event, the Separation from Service shall be deemed as a Normal Retirement that is not subject to the Retirement Conditions solely for purposes of establishing the timing for when such vesting is deemed to occur for purposes of this Agreement.

(d)    Change in Control Resulting in Delisting. Anything to the contrary herein notwithstanding, if a Change in Control occurs while the Subject Award is outstanding that results in the Company ceasing to be listed on a national securities exchange (a “Delisting Change in Control”), then the Tranche RIUs or Certified RIUs, if any, as applicable, shall vest, if at all, as follows:

(i)    If such a Delisting Change in Control occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then, subject to Participant satisfying the Retirement Conditions applicable to his or her Retirement, if any, the relevant Certified RIUs (without adjustment for the Prorated Amount) shall be deemed to vest as of (A) the applicable date pursuant to Section 3(c) if such Delisting Change in Control occurs on or after a Qualifying Termination, Retirement, death, or Qualifying Disability, (B) the date of a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, if the Delisting Change in Control occurs prior to a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, or (C) the applicable date pursuant to Section 3(a) above if not otherwise vested pursuant to the foregoing clauses.

(ii)    If such a Delisting Change in Control occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions applicable to his or her Retirement, if any, the relevant Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level as of (A) the date of such Delisting Change in Control if the Delisting Change in Control occurs on or after a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable (in which case, such vesting shall be adjusted for the Prorated Amount for a Qualifying Termination, an Early Retirement, and an Intermediate Retirement and otherwise occur without adjustment for the Prorated Amount), (B) the date of a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, if the Delisting Change in Control occurs prior to the Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, which vesting shall occur without adjustment for the Prorated Amount, or (C) the applicable date pursuant to Section 3(a) above if not otherwise vested pursuant to the foregoing clauses.

To the extent vesting applies pursuant to preceding paragraphs (i) and (ii) and the relevant Delisting Change in Control occurs prior to the delivery of Units, if any, described in Section 4 below, then the Company shall pay (in securities of a successor or surviving Person that are listed on a national securities exchange or if no such securities exist, then in cash) Participant an amount equal to the Change of Control Price (as defined in the Plan) for each of the relevant Certified RIUs for purposes of Section 4 below.

4.    Certification of Performance; Payment.

(a)    Certification. As soon as reasonably practicable following the close of a Performance Period that relates to a Subject Tranche, the Committee shall determine and certify (i) the extent to which the applicable Performance Goal as described on Schedule B is attained, and (ii) if at least Qualifying Performance is attained with respect to such Performance Goal (i.e., Qualifying Performance applies for such Subject Tranche), the number of the Certified RIUs that relate to such Subject Tranche. Such certification shall be final, conclusive, and binding on Participant, and on all other Persons, to the maximum extent permitted by law; provided, however, that Participant shall have the right at all reasonable times prior to or after any such certification to audit the books and records of the Committee and the Company, including the ability to make and retain copies of same, to the extent reasonably necessary to verify compliance with the terms and conditions of this Agreement, including, in particular, the calculations, workpapers, or other documents prepared and used in connection with making any such certification. For the avoidance of doubt, the Committee shall be deemed to have completed the certifications with

Exhibit 10.1

respect to clauses (i) and (ii) above when vesting is deemed to occur at the “Target” performance level pursuant to Section 3(c) or Section 3(d).

(b)    Payment. Subject to the “Six-Month Delay Toggle” (as defined in Section 15 of this Agreement), Units representing Certified RIUs shall be delivered to Participant no later than (i) if vesting occurs pursuant to Section 3(c), the 15th day of the third calendar month following the date on which vesting occurs (it being understood that in circumstances where Tranche RIUs remain eligible for vesting as Certified RIUs pursuant to Section 3(c), Units relating to the applicable Certified RIUs shall be delivered no later than the 15th day of the third calendar month following the relevant Tranche Valuation Date) and (ii) otherwise, 75 days following the End Date. Such Units representing Certified RIUs shall be delivered free of all restrictions to Participant or Participant’s beneficiary or estate, as the case may be (it being understood that the entry on the transfer agent’s books or the delivery of the certificate(s) with respect to such Units shall constitute delivery of such Units for purposes of this Agreement).

5.    Distribution Equivalent Payment Rights. Each Subject Tranche hereunder includes a tandem award of Distribution Equivalent Rights that shall apply throughout the Performance Period. Such Distribution Equivalent Rights shall entitle Participant to receive cash payments equal to the cash distributions made by the Company (on a per Unit basis) in respect of its outstanding Units generally (“General Distributions”). Except as provided below, such cash payments (“Distribution Equivalent Payments”) shall be payable to the extent the Tranche RIUs that relate to such Subject Tranche ultimately vest as Certified RIUs pursuant to this Agreement. No Distribution Equivalent Payments shall be made if such Tranche RIUs do not vest as Certified RIUs, are forfeited, or are otherwise canceled. Accordingly, (i) payment of such Distribution Equivalent Payments shall be made at the same time, and shall be subject to the same conditions, as are applicable to the delivery of Units with respect to such Certified RIUs (the “Delivered Units”), and (ii) the amount of such Distribution Equivalent Payments shall be equal to the aggregate General Distributions that would have been made on the Delivered Units if such Delivered Units were held by Participant from the beginning of the First Performance Period through the date on which such Delivered Units are delivered to Participant. No interest shall be credited on any Distribution Equivalent Payments.

6.    Taxes.

(a)    REPRESENTATION. PARTICIPANT REPRESENTS THAT PARTICIPANT IS NOT RELYING ON THE COMPANY OR ITS AFFILIATES FOR ANY TAX ADVICE IN CONNECTION WITH THE RESTRICTED INCENTIVE UNITS AND THAT PARTICIPANT HAS BEEN, OR IS OTHERWISE HEREBY, ADVISED TO CONSULT WITH ITS OWN TAX ADVISOR WITH RESPECT TO THE AWARD OF RESTRICTED INCENTIVE UNITS UNDER THIS AGREEMENT.

(b)    Withholding Matters.

(i)    The Company, its Affiliates, as applicable, and Participant shall comply with all federal and state laws and regulations respecting the withholding, deposit, and payment of any income, employment (including Federal Insurance Contributions Act (“FICA”) taxes), or other taxes relating to the Subject Award, including with respect to Distribution Equivalent Payments described in Section 5 of this Agreement. Such withholding shall be made by the Company or its Affiliates in accordance with the applicable withholding laws and regulations that are in effect at the time such withholding is required. Participant shall pay to the Company or its Affiliates, or make arrangements satisfactory to the Company or its Affiliates regarding payment of, any such withholding with respect to (A) Distribution Equivalent Payments and (B) the Restricted Incentive Units.

(ii)    Participant shall, to the extent permitted by law, have the right to elect for the Company or its Affiliates to withhold Units to which Participant is otherwise entitled upon the vesting of the Restricted Incentive Units (or Participant may deliver to the Company other unrestricted Units owned by Participant or deliver to the Company or its Affiliates Units that Participant has previously acquired), in each case valued at the Fair Market Value of such Units at the time of such withholding by, or delivery to, the Company or its Affiliates, to satisfy the obligation of Participant under Section 6(b)(i) of this Agreement (it being understood that the Fair Market Value of all such Units withheld or delivered may not exceed the amount of withholding due based on the withholding rate(s) applied by the Company, in its discretion, in accordance with the applicable withholding laws and regulations that are in effect at the time such withholding is required); provided, however, that in no event shall

Exhibit 10.1

any Units (or cash) that may be delivered hereunder be used to satisfy any FICA taxes that become due as a result of Participant being or becoming eligible for Retirement, Qualifying Termination or Qualifying Disability without having undergone such termination. Any payment of required withholding taxes by Participant in the form of Units shall not be permitted if it would result in an accounting charge with respect to such Units used to pay such taxes unless otherwise approved by the Committee.

(iii)    Any provision of this Agreement to the contrary notwithstanding, if Participant does not otherwise satisfy the obligations of Participant under Section 6(b)(i) of this Agreement, Participant acknowledges and agrees that the Company and its Affiliates shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due from the Company or its Affiliates to or with respect to Participant, whether or not pursuant to this Agreement or the Plan and regardless of the form of payment, any federal, state, or local taxes of any kind required by law to be withheld with respect to any Distribution Equivalent Payments or Restricted Incentive Units hereunder.

7.    Non-Assignability. Neither the Subject Award nor the Restricted Incentive Units is assignable or transferable by Participant, and, the Restricted Incentive Units shall not be assigned, alienated, pledged, attached, sold, or otherwise transferred or encumbered by Participant in any manner.

8.    Entirety and Modification. This Agreement (including all schedules hereto) contains the entire agreement between the parties hereto with respect to the subject matter hereof and supersedes any and all prior agreements, whether written or oral, between such parties relating to such subject matter. Subject to Section 15.2 of the Plan, no modification, alteration, amendment, or supplement to this Agreement shall be valid or effective unless the same is in writing and signed by the party against whom it is sought to be enforced.

9.    Severability. If any provision of this Agreement is held to be unenforceable, this Agreement shall be considered divisible, and such provision shall be deemed inoperative to the extent it is unenforceable, and in all other respects this Agreement shall remain in full force and effect; provided, however, that if any such provision may be made enforceable by limitation thereof, then such provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable law.

10.    Gender. Words used in this Agreement which refer to Participant and denote the male gender shall also be deemed to include the female gender or the neuter gender when appropriate.

11.    Employment or Service. Nothing in this Agreement shall confer upon Participant any right to continue in the employ or service of the Company or its Affiliates, nor shall this Agreement interfere in any manner with the right of the Company or its Affiliates to terminate the employment or service of Participant with or without Cause at any time.

12.    Incorporation of Plan Provisions. This Agreement is made pursuant to the Plan and is subject to all of the terms and provisions of the Plan as if the same were fully set forth herein. In the event that any provision of this Agreement conflicts with the Plan, the provisions of the Plan shall control. Participant acknowledges receipt of a copy of the Plan and agrees that all decisions under and interpretations of the Plan by the Committee shall be final, binding, and conclusive upon Participant.

13.    Headings. The headings of the various sections and subsections of this Agreement have been inserted for convenient reference only and shall not be construed to enlarge, diminish, or otherwise change the express provisions hereof.

14.    Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the state of Delaware (regardless of the laws that might otherwise govern under applicable Delaware principles of conflicts of law).

15.    Section 409A. The compensation payable pursuant to the Subject Award is intended to be exempt from, or otherwise in compliance with, Section 409A of the Code and this Agreement shall be administered and construed to the fullest extent possible to reflect and implement such intent. For purposes of Section 409A of the Code, each Subject Tranche shall be treated as a right to receive a separate and distinct payment. Anything to the

Exhibit 10.1

contrary herein notwithstanding, if, at the time of a Participant’s Separation from Service with the Company and its Affiliates, such Participant is a “specified employee” (as defined in Section 409A of the Code), and the deferral of the commencement of any amount of the payments or benefits otherwise payable pursuant to the Plan is necessary in order to prevent any accelerated or additional tax under Section 409A of the Code, then, to the extent permitted by Section 409A of the Code, such payments or benefits hereunder (without any reduction in the payments or benefits ultimately paid or provided to Participant) will be deferred until the earlier to occur of (i) Participant’s death or (ii) the first business day that is six months following Participant’s Separation from Service with the Company and its Affiliates(the “Six-Month Delay Toggle”). Any payments or benefits deferred due to the Six-Month Delay Toggle will be paid in a lump sum (without interest) to Participant on the earliest to occur of clause (i) or (ii) in the immediately preceding sentence.

16.    No Voting Rights. Anything to the contrary herein notwithstanding, in no event shall Participant have any right to vote any, or to exercise any other rights, powers, and privileges of a holder of the Units with respect to any Restricted Incentive Units granted hereunder until such time that (i) the Performance Period applicable to such Restricted Incentive Units or a portion thereof shall have expired (and all other conditions to payment with respect thereto have been fulfilled), (ii) such Restricted Incentive Units are converted into the right to receive Units, and (iii) such Units are delivered to Participant.

17.    Counterparts. This Agreement may be signed in counterparts, each of which shall be deemed an original and all of which shall constitute one and the same agreement.

Exhibit 10.1

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the Grant Date.

ENLINK MIDSTREAM, LLC

By: EnLink Midstream Manager, LLC

By:__________________________________________

Jesse Arenivas

Chief Executive Officer

PARTICIPANT:

__________________________________________

Exhibit 10.1

SCHEDULE A

SUBJECT TRANCHE LISTING (1)

Tranche Number	Relevant Performance Period for Subject Tranche	Relevant Performance Goal for Subject Tranche	Number of Restricted Incentive Units under Subject Tranche
1	First Performance Period	TSR	[●]
2	Second Performance Period	TSR	[●]
3	Third Performance Period	TSR	[●]
4	Cumulative Performance Period	TSR	[●]
5	First Performance Period	Cash Flow	[●]
6	Second Performance Period	Cash Flow	[●]
7	Third Performance Period	Cash Flow	[●]

____________________________

(1)Weighting of TSR to DCF will be 70%/30% of aggregate award.

Exhibit 10.1

SCHEDULE B

PERFORMANCE PERIOD, PERFORMANCE GOALS, AND PAYOUT AMOUNTS

1.    Performance Period. The number of Tranche RIUs that relate to a Subject Tranche, which can vest as Certified RIUs pursuant to the Subject Award, shall be calculated based on the level of Performance Goal achievement over the Performance Period that relates to such Subject Tranche.

2.    Performance Goals. The Performance Goal with respect to a Subject Tranche shall be based on either total shareholder return (“TSR”) or Cash Flow as such terms are further described below.

3.    TSR-Related Definitional Matters and Vesting Requirements. At the end of each Performance Period, the TSR for the Company and for each Peer Company (as described below) shall be determined pursuant to the following formula and in accordance with the following definitions and rules:

TSR = ((Closing Average Value - Opening Average Value) + Reinvested Dividends) ÷ Opening Average Value*

*The result shall be rounded to the nearest hundredth of one percent (.01%).

(a)    “Closing Average Value” means the average value of the common equity security for the 30 trading days ending on the last day of the Performance Period, which shall be calculated as follows: (A) determine the closing price of the common equity security on each trading date during 30-day period and (B) average the amounts so determined for the 30-day period.

(b)    “Opening Average Value” means the average value of the common equity security for the 30 trading days preceding the start of the Performance Period, which shall be calculated as follows: (A) determine the closing price of the common equity security on each trading date during the 30-day period and (B) average the amounts so determined for the 30-day period.

(c)    “Reinvested Dividends” means the dollar amount equal to (A) the aggregate number of the Company’s common units / shares (including fractional common units / shares) that could have been purchased during the Performance Period had each cash distribution / dividend paid on one common unit / share at the beginning of the Performance Period been immediately reinvested in additional units / shares (or fractional common units / shares) at the closing selling price per common unit / share on the applicable distribution / dividend payment date (it being understood that the calculation in this clause (A) will include a compounding of distributions / dividends paid on common units / shares (or fractional common units / shares) “purchased” during the Performance Period from prior distribution / dividend “reinvestments”) multiplied by (B) the Closing Average Value.

(d)    Each of the foregoing amounts shall be equitably adjusted for share / unit splits, stock dividends or unit distributions, recapitalizations, and other similar events affecting the common equity securities in question.

Exhibit 10.1

(e)    The Committee shall determine the number of Tranche RIUs that vest, if at all, as Certified RIUs pursuant to this Agreement based on the Company’s relative TSR ranking in respect of the Performance Period as compared to the TSR ranking of the Peer Companies as follows:

Performance Level	The Company’s Achieved TSR Percentile Position Relative to Peer Companies*	Associated Individual Payout Level (expressed as a percentage of the Tranche RIUs)
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater than or Equal to 85%	200%

*If the Company’s achieved TSR percentile position is between the Threshold and Target performance levels or if the Company’s achieved TSR percentile position is between the Target and Maximum performance levels, then the associated individual payout level will be interpolated on a linear basis. If the Company’s final TSR value is equal to the TSR value of a Peer Company, the Committee shall assign the Company the higher ranking.

(f)    The Peer Companies are the companies set forth on Schedule C to this Agreement; provided, however, that the Peer Companies will be subject to change as follows:

(i)    If on or before the date that is 30-trading days into a given Performance Period, a Peer Company enters into, becomes subject to, or is the subject of a definitive agreement or a filing made with the SEC contemplating an acquisition, merger, tender offer, or other similar transaction (regardless of whether such transaction is a Simplification Transaction or otherwise) (collectively, a “Transaction”) that involves such Peer Company and that, if consummated, would result (or reasonably be expected to result) in such Peer Company ceasing to be traded on a national securities exchange (“Traded”), then such Peer Company will be eliminated from the TSR calculations for all Performance Periods that end on a date subsequent to the date of such definitive agreement or SEC filing, as applicable (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing). If, however, such Transaction is rescinded, revoked, terminated, or abandoned, then such Peer Company will remain a Peer Company and again be subject to all of the terms set forth herein (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing).

(ii)    If on or after the date that is 31-trading days into a given Performance Period and before the last day of the relevant Performance Period, a Peer Company enters into, becomes subject to, or is the subject of a definitive agreement or a filing made with the SEC contemplating a Transaction (other than a Simplification Transaction, which is addressed below) that involves such Peer Company and that, if consummated, would result (or reasonably be expected to result) in such Peer Company ceasing to be Traded, then such Peer Company will be fixed above or below the Company for relative TSR purposes calculating the Company’s and the applicable Peer Company’s TSRs using the trading day preceding the date on which the public became aware of such a definitive agreement or SEC filing, as applicable, as the end date for “Closing Average Value” purposes. If such calculation results in such Peer Company being fixed above the Company, then the Committee shall assign the Peer Company with a TSR that places such Peer Company at the top of the TSR rankings, and if fixed below the Company, then the Committee shall assign the Peer Company with a TSR that places such Peer Company at the bottom of the TSR rankings, in each case, for all Performance Periods that end on a date subsequent to the date of the definitive agreement or SEC filing, as applicable (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing). If, however, such Transaction is rescinded, revoked, terminated, or abandoned, then such Peer Company will remain a Peer Company and again be subject to all of the terms set forth herein (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing).

(iii)    If on or after the date that is 31-trading days into a given Performance Period and before the last day of the relevant Performance Period, a Peer Company enters into, becomes subject to, or is the subject of

Exhibit 10.1

a definitive agreement or a filing made with the SEC contemplating a Simplification Transaction that involves such Peer Company and that, if consummated, would result (or reasonably be expected to result) in such Peer Company ceasing to be Traded, then the survivor of such Simplification Transaction that remains Traded shall be deemed to have been and to be a Peer Company (in each case, for purposes of each component of the TSR calculation) for all Performance Periods that end on a date subsequent to the date of such definitive agreement or SEC filing, as applicable (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing). If, however, such Simplification Transaction is rescinded, revoked, terminated, or abandoned, then such Peer Company will remain a Peer Company and again be subject to all of the terms set forth herein (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing).

(iv)    A Peer Company that is both involved in a bankruptcy proceeding and ceases to be Traded during a Performance Period will remain a Peer Company but shall be deemed to have a TSR of negative 100% (-100%) for all Performance Periods that end on a date subsequent to the date of such delisting. A Peer Company that is involved in a bankruptcy proceeding, but remains Traded will remain a Peer Company and no adjustment shall be made.

(v)    A Peer Company that ceases to be Traded during a Performance Period for a reason other than one contemplated in clauses (i) through (iv) above will remain a Peer Company but shall be deemed to have a TSR of negative 100% (-100%) for all Performance Periods that end on a date subsequent to the date of such delisting.

(g)    “Simplification Transaction” means a transaction in the form of what is known in the MLP space as a “simplification” transaction and where the operating assets of the master limited partnership involved in such transaction constitute substantially all of the assets owned by the relevant parent entity involved in such transaction.

4.    Cash Flow-Related Definitional Matters and Vesting Requirements.

(a)“Cash Flow” with respect to any relevant Performance Period shall consist of the measurement “distributable cash flow” (“DCF”) and shall be calculated consistent with the Company’s most relevant published financial results for a given Performance Period (the applicable “Reference Year”) and means, (A) the Company’s Adjusted EBITDA, net to EnLink Midstream LLC, (as defined and calculated consistent with the Company’s most relevant published financial results or guidance) minus (B) the sum of (u) interest expense, net of interest income, (v) accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid, (w) maintenance capital expenditures (excluding maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of the Company’s consolidated entities), (x) payments to terminate interest rate swaps, (y) noncash interest income and (z) current income tax expenses, plus (C) noncash interest expense and current income tax benefit. For the avoidance of doubt, actual DCF for any applicable Reference Year shall be calculated on a pre-bonus basis (i.e., before the STI payout).

(b)Prior to the certification of DCF performance by the Committee for a given Reference Year, Target DCF (as set forth in the chart below) may be adjusted for merger and acquisition activity, large capital growth projects, and any other events or items during the Reference Year that were unforeseen when the performance targets were established. Management shall propose such adjustments for consideration by the Committee. If the Committee, acting in its discretion, approves any such adjustments, the Target DCF for such Reference Year shall be adjusted by the amount so approved.

Exhibit 10.1

(c)The Committee shall determine the number of Tranche RIUs that vest, if at all, as Certified RIUs pursuant to this Agreement based on the Company’s actual achieved DCF for the Performance Period ending December 31, 2023, as compared to the Target DCF as follows:

Performance Level	Target DCF*‡	Associated Individual Payout Level (expressed as a percentage of the Tranche RIUs)
Below Threshold	Less than $817	0%
Threshold	Equal to $817	50%
Target	Equal to $958	100%
Maximum	Greater than or equal to $1,169	200%

*If the Company’s actual achieved DCF is between the Threshold and Target performance levels or if the Company’s achieved DCF is between the Target and Maximum performance levels, then the associated individual payout level will be interpolated on a linear basis.

‡Amounts shown above as Target DCF apply for the First Performance Period, are shown on a pre-bonus basis, and are shown before adjustments, if any, are made pursuant to paragraph (b), above. The successive Performance Period Target DCF will be updated as set forth in paragraph (d) below.

(d)    For the Second Performance Period and the Third Performance Period, the Board, or the Committee, will establish the figures to be included in the column titled “Target DCF” in the chart above and will notify Participant of the same in writing no later than March 31 of the year in which the relevant Performance Period begins.

5.    Other Vesting Terms. Any fractional Certified RIUs resulting from the vesting thereof in accordance with this Agreement shall be rounded down to the nearest whole number. Any portion of the Tranche RIUs that does not vest as Certified RIUs of the end of the Performance Period shall be forfeited as of the end of the Performance Period.

Exhibit 10.1

SCHEDULE C

PEER COMPANIES

Antero Midstream GP	Kinder Morgan, Inc.
Cheniere Energy, Inc.	Kinetik Holdings, Inc.
Cheniere Energy Partners, LP	Magellan Midstream Partners, LP
Crestwood Equity Partners, LP	MPLX, LP
DCP Midstream, LP	NGL Energy Partners
Delek Logistics Partners, LP	NuStar Energy, LP
DT Midstream	ONEOK, Inc.
Energy Transfer, LP	Plains All American Pipeline, LP
Enterprise Products Partners, LP	Plains GP Holdings
Equitrans Midstream Corp.	Shell Midstream Partners
Genesis Energy, LP	Targa Resources Corp.
Hess Midstream Partners LP	The Williams Companies, Inc.
Holly Energy Partners	Western Gas Equity Partners, LP

Exhibit 10.1

SCHEDULE D

RESTRICTIVE COVENANTS

For the avoidance of doubt, Participant only makes the agreements contemplated in, and is only bound by, this Schedule D in connection with his or her Early Retirement, Intermediate Retirement, or Normal Retirement. In partial consideration for Participant’s access to confidential information (the access to which Participant hereby acknowledges) and eligibility for and receipt of the benefits provided by Early Retirement, Intermediate Retirement, or Normal Retirement by that certain Performance Unit Agreement to which this Schedule D is attached (the “Agreement”), Participant hereby agrees as follows:

1.Restrictive Covenants.

(i)    Covenant Not to Solicit Customers. Participant agrees that while employed by a member of the Company Group and for a period of twelve (12) months after his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable, Participant shall not (i) persuade or encourage any Person that was a client or customer of EnLink Midstream, LLC or any of its direct or indirect subsidiaries (collectively, the “Company Group”) at any time during the twelve (12) months prior to his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable, to cease conducting or fail to renew existing business with that member of the Company Group, or (ii) use any confidential or proprietary information of any member of the Company Group to directly or indirectly solicit business from, or to interrupt, disturb, or interfere with any member of the Company Group’s relationships with, any Person that was a client or customer of any member of the Company Group at any time during the twelve (12) months prior to his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable.

(ii)    Covenant not to Solicit Employees. Participant agrees that while employed by any member of the Company Group and for a period of twenty-four (24) months after his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable, Participant shall not solicit, endeavor to entice, or induce any employee of any member of the Company Group to terminate such Person’s employment or service with such member or accept employment with anyone else; provided, however, that a general solicitation of the public for employment shall not constitute a solicitation hereunder.

2.    Specific Performance. Recognizing that irreparable damage will result to the Company Group in the event of the breach or threatened breach of any of the foregoing covenants and assurances by Participant contained in paragraph 1 of this Schedule D, and that the Company Group’s remedies at law for any such breach or threatened breach will be inadequate, the members of the Company Group and their successors and assigns, in addition to such other remedies that may be available to them, shall be entitled to an injunction, including a mandatory injunction (without the necessity of (i) proving irreparable harm, (ii) establishing that monetary damages are inadequate, or (iii) posting any bond with respect thereto), to be issued by any court of competent jurisdiction ordering compliance with the Agreement or enjoining and restraining Participant, and each and every Person, firm, or company acting in concert or participation with him or her, from the continuation of such breach and, in addition thereto, he or she shall pay to such affected member of the Company Group all ascertainable damages, including costs and reasonable attorneys’ fees sustained by such affected member or members of the Company Group by reason of the breach or threatened breach of said covenants and assurances.

3.    Clawback. Participant agrees that in the event that the Committee determines that Participant has breached any term of this Schedule D, in addition to any other remedies at law or in equity that any affected member of the Company Group may have available to it or them, the Committee may in its sole discretion require that Participant, within five (5) business days of receipt of written demand therefor, repay to the Company the amount of any Distribution Equivalent Payments paid to Participant pursuant to Section 5 of the Agreement and return to the Company the Units (or other benefits) delivered to Participant in connection with Section 4 of the Agreement (or in the event Participant has ceased to hold such Units (or other benefits), an amount equal to the Fair Market Value thereof as in effect as of the date of such written demand).

Exhibit 10.1

4.    Miscellaneous.

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

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

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

(d)    The restrictive covenants set forth in this Schedule D are personal and not assignable by Participant but they may be assigned by the Company without notice to or consent of Participant to, and shall thereafter be binding upon and enforceable by, (i) any member of the Company Group, or (ii) any Person that acquires or succeeds to substantially all of the business or assets of any member of the Company Group (and such Person shall be deemed included to be in the definition of the “Company” and the “Company Group” for all purposes of this Schedule D).

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Jesse Arenivas, 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 3, 2023	/s/ JESSE ARENIVAS
	Jesse Arenivas
	Chief Executive Officer
	(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Benjamin D. Lamb, 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 3, 2023	/s/ BENJAMIN D. LAMB
	Benjamin D. Lamb
	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, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned, Jesse Arenivas, Chief Executive Officer of EnLink Midstream Manager, LLC, and Benjamin D. Lamb, 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 3, 2023	/s/ JESSE ARENIVAS
	Jesse Arenivas
	Chief Executive Officer
Date: May 3, 2023	/s/ BENJAMIN D. LAMB
	Benjamin D. Lamb
	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, 2023	Apr. 27, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2023
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)		465,989,285
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2023
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, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents		$ 72.8	$ 22.6
Accounts receivable:
Trade receivables	[1]	86.3	89.2
Accrued revenue and other		537.5	636.0
Fair value of derivative assets		68.5	68.4
Other current assets		94.0	166.6
Total current assets		859.1	982.8
Property and equipment, net of accumulated depreciation of $4,898.8 and $4,774.5, respectively		6,543.4	6,556.0
Intangible assets, net of accumulated amortization of $955.5 and $923.6, respectively		889.3	921.2
Investment in unconsolidated affiliates		140.4	90.2
Fair value of derivative assets		13.6	2.9
Other assets, net		100.6	97.9
Total assets		8,546.4	8,651.0
Current liabilities:
Accounts payable and drafts payable		111.4	126.9
Accrued gas, NGLs, condensate, and crude oil purchases	[2]	360.0	476.0
Fair value of derivative liabilities		41.1	42.9
Other current liabilities		195.9	229.6
Total current liabilities		708.4	875.4
Long-term debt, net of unamortized issuance cost		4,828.0	4,723.5
Other long-term liabilities		96.6	94.0
Deferred tax liability, net		53.2	42.7
Fair value of derivative liabilities		18.3	2.7
Members’ equity:
Members’ equity (467,137,866 and 468,980,630 units issued and outstanding, respectively)		1,238.7	1,306.4
Accumulated other comprehensive loss		(1.2)	0.0
Non-controlling interest		1,604.4	1,606.3
Total members’ equity		2,841.9	2,912.7
Commitments and contingencies (Note 16)
Total liabilities and members’ equity		$ 8,546.4	$ 8,651.0

[1] There was no allowance for bad debt at March 31, 2023. Includes allowance for bad debt of $0.1 million at December 31, 2022.

[2] Includes related party accounts payable balances of $1.2 million and $2.5 million at March 31, 2023 and December 31, 2022, respectively.

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
ASSETS
Property and equipment, accumulated depreciation	$ 4,898.8	$ 4,774.5
Intangible assets, accumulated amortization	$ 955.5	$ 923.6
Members’ equity:
Common units issued (in shares)	467,137,866	468,980,630
Common units outstanding (in shares)	468,980,630	467,137,866
Allowance for bad debt	$ 0.0	$ 0.1
Accounts payable to related party	$ 1.2	$ 2.5

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Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2023	Mar. 31, 2022
Revenues:
Revenue from contracts with customers		$ 1,755.6	$ 2,258.9
Gain (loss) on derivative activity		11.9	(31.2)
Total revenues		1,767.5	2,227.7
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	1,271.9	1,794.5
Operating expenses		132.4	120.9
Depreciation and amortization		160.4	152.9
(Gain) loss on disposition of assets		(0.4)	5.1
General and administrative		29.5	29.0
Total operating costs and expenses		1,593.8	2,102.4
Operating income		173.7	125.3
Other income (expense):
Interest expense, net of interest income		(68.5)	(55.1)
Loss from unconsolidated affiliate investments		(0.1)	(1.1)
Other income		0.0	0.1
Total other expense		(68.6)	(56.1)
Income before non-controlling interest and income taxes		105.1	69.2
Income tax expense		(10.9)	(3.2)
Net income		94.2	66.0
Net income attributable to non-controlling interest		36.0	30.8
Net income attributable to ENLC		$ 58.2	$ 35.2
Net income attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ 0.12	$ 0.07
Diluted common unit (in dollars per share)		$ 0.12	$ 0.07
Product sales
Revenues:
Revenue from contracts with customers		$ 1,476.3	$ 2,043.9
Midstream services
Revenues:
Revenue from contracts with customers		$ 279.3	$ 215.0

[1] Includes related party cost of sales of $1.5 million and $10.6 million for the three months ended March 31, 2023 and 2022, respectively.

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Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Statement [Abstract]
Related party cost of sales	$ 1.5	$ 10.6

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Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2023	Mar. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income		$ 94.2	$ 66.0
Unrealized gain (loss) on designated cash flow hedge	[1]	(1.2)	0.1
Comprehensive income		93.0	66.1
Comprehensive income attributable to non-controlling interest		36.0	30.8
Comprehensive income attributable to ENLC		$ 57.0	$ 35.3

[1] Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

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Consolidated Statements of Comprehensive Income (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)
Statement of Comprehensive Income [Abstract]
Tax benefit	$ 0.4

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Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions	Total		Common Units	Accumulated Other Comprehensive Loss		Non-Controlling Interest
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			484,300,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes	(4.2)		$ (4.2)
Conversion of unit-based awards 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 (loss) on designated cash flow hedge	0.1	[1]		0.1
Redemption of Preferred Units	(50.5)					(50.5)
Common units repurchased	$ (17.0)		$ (17.0)
Common units repurchased (in shares)	(2,093,842)		(2,100,000)
Net income	$ 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			483,400,000
Member equity, beginning balance at Dec. 31, 2022	$ 2,912.7		$ 1,306.4	0.0		1,606.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2022	468,980,630		469,000,000.0
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes	$ (16.8)		$ (16.8)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)			2,500,000
Unit-based compensation	4.0		$ 4.0
Contributions from non-controlling interests	8.4					8.4
Distributions	(104.1)		(61.7)			(42.4)
Unrealized gain (loss) on designated cash flow hedge	(1.2)	[1]		(1.2)	[2]
Redemption of Preferred Units	(3.9)					(3.9)
Common units repurchased	$ (51.4)		$ (51.4)
Common units repurchased (in shares)	(4,444,415)		(4,400,000)
Net income	$ 94.2		$ 58.2			36.0
Member equity, end balance at Mar. 31, 2023	$ 2,841.9		$ 1,238.7	$ (1.2)		$ 1,604.4
Units outstanding, end balance (in shares) at Mar. 31, 2023	467,137,866		467,100,000

[1] Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

[2] Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

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Consolidated Statement of Changes in Members' Equity (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)
Statement of Stockholders' Equity [Abstract]
Tax benefit	$ 0.4

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash flows from operating activities:
Net income	$ 94.2	$ 66.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	160.4	152.9
Utility credits redeemed	1.4	5.6
Deferred income tax expense	10.8	3.0
(Gain) loss on disposition of assets	(0.4)	5.1
Non-cash unit-based compensation	4.0	6.6
Non-cash loss on derivatives recognized in net income	1.4	17.3
Amortization of debt issuance costs and net discount of senior unsecured notes	1.5	1.3
Loss from unconsolidated affiliate investments	0.1	1.1
Other operating activities	0.3	(1.1)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	101.1	(139.9)
Natural gas and NGLs inventory, prepaid expenses, and other	68.3	(32.8)
Accounts payable, accrued product purchases, and other accrued liabilities	(171.0)	222.6
Net cash provided by operating activities	272.1	307.7
Cash flows from investing activities:
Additions to property and equipment	(100.7)	(60.2)
Contributions to unconsolidated affiliate investments	(49.7)	0.0
Other investing activities	0.4	1.0
Net cash used in investing activities	(150.0)	(59.2)
Cash flows from financing activities:
Proceeds from borrowings	1,173.0	500.0
Repayments on borrowings	(1,067.4)	(550.0)
Distributions to members	(61.7)	(56.4)
Distributions to non-controlling interests	(42.4)	(34.6)
Payment to redeem mandatorily redeemable non-controlling interest	(10.5)	0.0
Contributions from non-controlling interests	8.4	7.3
Common unit repurchases	(51.4)	(17.0)
Conversion of unit-based awards for common units, net of units withheld for taxes	(16.8)	(4.2)
Other financing activities	0.8	(0.6)
Net cash used in financing activities	(71.9)	(206.0)
Net increase in cash and cash equivalents	50.2	42.5
Cash and cash equivalents, beginning of period	22.6	26.2
Cash and cash equivalents, end of period	72.8	68.7
Supplemental disclosures of cash flow information:
Cash paid for interest	62.2	29.4
Non-cash investing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	10.4	8.5
Non-cash accrual of property and equipment	13.4	(0.2)
Redemption of Series B Preferred Units
Cash flows from financing activities:
Redemption of Series B Preferred Units	0.0	(50.5)
Repurchase of Series C Preferred Units
Cash flows from financing activities:
Redemption of Series B Preferred Units	$ (3.9)	$ 0.0

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General

3 Months Ended

Mar. 31, 2023

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.” As of March 31, 2023, GIP, through GIP III Stetson I, L.P. and GIP III Stetson II, L.P, owns 41.3% of the outstanding limited liability company interests in ENLC. In addition to GIP’s equity interests in ENLC, GIP III Stetson I, L.P. maintains control over the Managing Member through its ownership of all of the equity interests in the Managing Member. 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.

As of March 31, 2023, our midstream energy asset network includes approximately 13,600 miles of pipelines, 26 natural gas processing plants with approximately 6.0 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, 2023

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, 2022 filed with the Commission on February 15, 2023. 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
2023 (remaining)	$	98.0
2024	114.9
2025	101.8
2026	100.7
2027	83.8
Thereafter	1,034.1
Total	$	1,533.3

c.Redeemable Non-Controlling Interest

During the first quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. At the time of the exercise, we and the interest holder did not agree on the value of the interest and a lawsuit was filed by the interest holder. As part of a settlement effected with the interest holder in January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest for $10.5 million.

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Acquisition

3 Months Ended

Mar. 31, 2023

Business Combination and Asset Acquisition [Abstract]

Acquisition

(3) Acquisition

Central Oklahoma Acquisition

On December 19, 2022, we completed the Central Oklahoma Acquisition. The acquired assets include approximately 900 miles of lean and rich gas gathering pipeline and two processing plants with 280 MMcf/d of total processing capacity. We completed this acquisition to increase the scale and efficiency of our Central Oklahoma assets.

The following table presents the preliminary fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Consideration
Cash (including working capital payment)	$	100.9
Contingent consideration	1.3
Total consideration	$	102.2
Purchase price allocation (1)
Assets acquired:
Current assets	$	6.0
Property and equipment	97.1
Other assets, net (2)	0.9
Liabilities assumed:
Current liabilities	(1.4)
Other long-term liabilities (2)	(0.4)
Net assets acquired	$	102.2

____________________________

(1)The purchase price allocation was based on preliminary estimates and assumptions, which are subject to change within the measurement period (up to one year from the acquisition date), as we finalize the valuations of the assets acquired and liabilities assumed upon the closing of the acquisition.

(2)“Other assets, net” and “Other long-term liabilities” consist of the right-of-use assets and lease liabilities, respectively, obtained through the Central Oklahoma Acquisition.

Contingent Consideration. The following table represents our change in carrying value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities for the periods presented (in millions):

	Three Months Ended March 31,
	2023		2022
Amarillo Rattler Acquisition contingent consideration
Contingent consideration liability, beginning of period (1)	$	4.2	$	6.9
Change in fair value	0.5		—
Contingent consideration liability, end of period	4.7		6.9
Central Oklahoma Acquisition contingent consideration
Contingent consideration liability, beginning of period (2)	1.3		—
Change in fair value	0.2		—
Contingent consideration liability, end of period	1.5		—
Total contingent consideration
Contingent consideration liability, beginning of period (1)(2)	5.5		6.9
Change in fair value	0.7		—
Contingent consideration liability, end of period	$	6.2	$	6.9

____________________________

(1)The contingent consideration for the Amarillo Rattler Acquisition was recorded on April 30, 2021.

(2)The contingent consideration for the Central Oklahoma Acquisition was recorded on December 19, 2022.

Pro Forma of Acquisitions for the Three Months Ended March 31, 2022

The following unaudited pro forma condensed consolidated financial information (in millions) for the three months ended March 31, 2022 gives effect to the Barnett Shale Acquisition on July 1, 2022 and the Central Oklahoma Acquisition on December 19, 2022 as if each of the acquisitions had occurred on January 1, 2022.

The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

	Three Months Ended March 31, 2022
Pro forma total revenues	$	2,256.9
Pro forma net income	$	75.2

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Intangible Assets

3 Months Ended

Mar. 31, 2023

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

(4) 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, 2023
Customer relationships, beginning of period	$	1,844.8	$	(923.6)	$	921.2
Amortization expense	—		(31.9)		(31.9)
Customer relationships, end of period	$	1,844.8	$	(955.5)	$	889.3

Amortization expense was $31.9 million and $32.8 million for the three months ended March 31, 2023 and 2022, respectively.

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

2023 (remaining)	$	95.7
2024	127.6
2025	110.2
2026	106.3
2027	106.3
Thereafter	343.2
Total	$	889.3

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Related Party Transactions

3 Months Ended

Mar. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

(5) Related Party Transactions

(a)    Transactions with Cedar Cove JV

For the three months ended March 31, 2023 and 2022, we recorded cost of sales of $1.5 million and $10.6 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 $1.2 million and $2.5 million at March 31, 2023 and December 31, 2022, respectively.

(b)    Transactions with GIP

General and Administrative Expenses. We did not record any expenses related to transactions with GIP and its affiliates for the three months ended March 31, 2023 and 2022.

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, 2023

Debt Disclosure [Abstract]

Long-Term Debt

(6) Long-Term Debt

As of March 31, 2023 and December 31, 2022, long-term debt consisted of the following (in millions):

	March 31, 2023						December 31, 2022
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Revolving Credit Facility due 2027 (1)	$	505.0	$	—	$	505.0	$	255.0	$	—	$	255.0
AR Facility due 2025 (2)	355.6		—		355.6		500.0		—		500.0
ENLK’s 4.40% Senior unsecured notes due 2024	97.9		—		97.9		97.9		—		97.9
ENLK’s 4.15% Senior unsecured notes due 2025	421.6		(0.1)		421.5		421.6		(0.1)		421.5
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.2)		490.8		491.0		(0.2)		490.8
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
ENLC’s 6.50% Senior unsecured notes due 2030	700.0		—		700.0		700.0		—		700.0
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.1)		444.9		450.0		(5.2)		444.8
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	$	4,869.8	$	(5.7)	4,864.1		$	4,764.2	$	(5.8)	4,758.4
Debt issuance cost (3)					(36.1)						(34.9)
Long-term debt, net of unamortized issuance cost					$	4,828.0					$	4,723.5

____________________________

(1)The effective interest rate was 6.9% and 6.5% at March 31, 2023 and December 31, 2022, respectively.

(2)The effective interest rate was 5.8% and 5.3% at March 31, 2023 and December 31, 2022, respectively.

(3)Net of accumulated amortization of $16.5 million and $15.1 million at March 31, 2023 and December 31, 2022, respectively.

Revolving Credit Facility

The Revolving Credit Facility permits ENLC to borrow up to $1.40 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. There were $505.0 million in outstanding borrowings under the Revolving Credit Facility and $43.6 million in outstanding letters of credit as of March 31, 2023.

At March 31, 2023, we were in compliance with and expect to be in compliance with the financial covenants of the Revolving Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, 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 $589.4 million as of March 31, 2023. As of March 31, 2023, the AR Facility had a borrowing base of $355.6 million and there were $355.6 million in outstanding borrowings under the AR Facility.

At March 31, 2023, 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.

Senior Unsecured Notes

On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of 6.500% senior notes due 2030 (the “Additional Notes”) at 99% of their face value. The Additional Notes were offered as an additional issue of our existing 6.500% senior notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million. Net proceeds of approximately $294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK.

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Income Taxes

3 Months Ended

Mar. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

(7) Income Taxes

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

	Three Months Ended March 31,
	2023		2022
Current income tax expense	$	(0.1)	$	(0.2)
Deferred income tax expense	(10.8)		(3.0)
Income tax expense	$	(10.9)	$	(3.2)

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,
	2023		2022
Expected income tax expense based on federal statutory rate	$	(14.5)	$	(8.1)
State income tax expense, net of federal benefit	(1.8)		(1.1)
Unit-based compensation (1)	6.5		(2.0)
Change in valuation allowance	—		7.1
Other	(1.1)		0.9
Income tax expense	$	(10.9)	$	(3.2)

____________________________

(1)Related to book-to-tax differences recorded upon the vesting of unit-based awards.

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, 2023, we had $53.2 million of deferred tax liabilities, net of $731.9 million of deferred tax assets. As of December 31, 2022, we had $42.7 million of deferred tax liabilities, net of $714.1 million of deferred tax assets.

We provide a valuation allowance, if necessary, to reduce deferred tax assets, if all, or some portion, of such assets will more than likely not be realized. We previously established a valuation allowance, primarily related to federal and state tax operating loss carryforwards for which we did not believe a tax benefit was more likely than not to be realized. As of March 31, 2023, we did not record a valuation allowance and management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets.

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Certain Provisions of the ENLK Partnership Agreement

3 Months Ended

Mar. 31, 2023

Partners' Capital [Abstract]

Certain Provisions of the ENLK Partnership Agreement

(8) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of March 31, 2023 and December 31, 2022, there were 54,168,359 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 represented 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we agreed with the holders of the Series B Preferred Units to pay cash in lieu of making a quarterly distribution in-kind of additional Series B Preferred Units (the “PIK Distribution”) through the distribution declared for the fourth quarter of 2022. Beginning with the quarterly distribution declared for the first quarter of 2023, we will resume paying a PIK distribution.

Income is allocated to the Series B Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2023 and 2022 is provided below:

Declaration period	PIK Distribution	Cash distribution (in millions)		Date paid/payable
2023
Fourth Quarter of 2022	—	$	17.3	February 13, 2023
First Quarter of 2023	135,421	$	15.2	May 12, 2023
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022.

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

For tax purposes, holders of Series B Preferred Units are allocated items of gross income from ENLK in respect of each Series B Preferred Unit until the cumulative amount of gross income so allocated equals the cumulative amount of distributions made in respect of such Series B Preferred Unit, but not in excess of such Series B Preferred Unit’s pro rata share of the net income of ENLK for the allocation year (the “Allocation Cap”). Because of the application of the Allocation Cap in 2022 and prior years, as of December 31, 2022, the cumulative amount of distributions made in respect of each Series B Preferred Unit exceeded the cumulative amount of gross income allocated to each Series B Preferred Unit by $5.99 per Series B Preferred Unit (the “Catch-Up Taxable Income Allocation”). As a result, holders of Series B Preferred Units will ultimately be allocated taxable income during future periods equal to the Catch-Up Taxable Income Allocation plus the amount of distributions received in respect of Series B Preferred Units, if ENLK generates positive net income.

b.Series C Preferred Units

Repurchase

In February 2023, we repurchased 4,500 Series C Preferred Units for total consideration of $3.9 million. The repurchase price represented 87% of the preferred units’ par value.

Distributions

Distributions on the Series C Preferred Units accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. Distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to the floating rate of the three-month LIBOR plus a spread of 4.11%. Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period.

As of March 31, 2023 and December 31, 2022, there were 376,500 and 381,000 Series C Preferred Units issued and outstanding, respectively. ENLK made distributions of $8.4 million to the holders of Series C Preferred Units during the three months ended March 31, 2023. There was no distribution activity for the three months ended March 31, 2022. For the distribution period of March 16, 2023 through June 15, 2023, the distribution rate per unit is 9.051%, which is comprised of the three-month LIBOR rate of 4.941% plus a spread of 4.11%. The distribution of $8.5 million is payable on June 15, 2023 to the holders of Series C Preferred Units.

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Members' Equity

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Members' Equity

(9) Members’ Equity

a.Common Unit Repurchase Program

In December 2022, the board of directors of the Managing Member (the “Board”) reauthorized our common unit repurchase program for 2023 and set the amount available for repurchases of outstanding common units during 2023 at up to $200.0 million, including repurchases of common units held by GIP. 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.

The following table summarizes our ENLC common unit repurchase activity for the periods presented (in millions, except for unit amounts):

	Three Months Ended March 31,
	2023		2022
Publicly held ENLC common units	2,207,305		2,093,842
ENLC common units held by GIP (1)	2,237,110		—
Total ENLC common units	4,444,415		2,093,842
Aggregate cost for publicly held ENLC common units	$	26.8	$	17.0
Aggregate cost for ENLC common units held by GIP	24.6		—
Total aggregate cost for ENLC common units	$	51.4	$	17.0
Average price paid per publicly held ENLC common unit	$	12.14	$	8.12
Average price paid per ENLC common unit held by GIP (2)	$	11.01	$	—

____________________________

(1)For the three months ended March 31, 2023, the 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 fourth quarter of 2022.

(2)For the three months ended March 31, 2023, the per unit price we paid to GIP was the average per unit price paid by us for publicly held ENLC common units repurchased, less broker commissions, during the fourth quarter of 2022.

Additionally, on May 1, 2023, we repurchased 1,910,877 ENLC common units held by GIP at an aggregate cost of $23.2 million, or an average of $12.12 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended March 31, 2023. The per unit price we paid to GIP was the same as the average per unit price paid by us for publicly held ENLC common units repurchased during the same period, less broker commissions, which were not paid with respect to the GIP units.

b.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,
	2023		2022
Distributed earnings allocated to:
Common units (1)	$	58.6	$	54.4
Unvested unit-based awards (1)	0.9		1.1
Total distributed earnings	$	59.5	$	55.5
Undistributed loss allocated to:
Common units	$	(1.3)	$	(19.9)
Unvested unit-based awards	—		(0.4)
Total undistributed loss	$	(1.3)	$	(20.3)
Net income attributable to ENLC allocated to:
Common units	$	57.3	$	34.5
Unvested unit-based awards	0.9		0.7
Total net income attributable to ENLC	$	58.2	$	35.2
Net income attributable to ENLC per unit:
Basic	$	0.12	$	0.07
Diluted	$	0.12	$	0.07

____________________________

(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,
	2023	2022
Basic weighted average units outstanding:
Weighted average common units outstanding	468.9	484.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	468.9	484.0
Dilutive effect of unvested unit-based awards	4.4	6.6
Total weighted average diluted common units outstanding	473.3	490.6

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.

c.Distributions

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2023 and 2022, respectively, is provided below:

Declaration period	Distribution/unit		Date paid/payable
2023
Fourth Quarter of 2022	$	0.12500	February 13, 2023
First Quarter of 2023	$	0.12500	May 12, 2023
2022
Fourth Quarter of 2021	$	0.11250	February 11, 2022
First Quarter of 2022	$	0.11250	May 13, 2022

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Investment in Unconsolidated Affiliates

3 Months Ended

Mar. 31, 2023

Equity Method Investments and Joint Ventures [Abstract]

Investment in Unconsolidated Affiliates

(10) Investment in Unconsolidated Affiliates

As of March 31, 2023, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):

	Three Months Ended March 31,
	2023		2022
GCF
Contributions	$	6.2	$	—
Equity in loss	$	(1.1)	$	(0.7)
Cedar Cove JV
Distributions	$	(0.1)	$	(0.2)
Equity in loss	$	(0.6)	$	(0.4)
Matterhorn JV
Contributions	$	43.5	$	—
Equity in income	$	1.6	$	—
Total
Contributions	$	49.7	$	—
Distributions	$	(0.1)	$	(0.2)
Equity in loss	$	(0.1)	$	(1.1)

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2023 and December 31, 2022 (in millions):

	March 31, 2023		December 31, 2022
GCF	$	31.4	$	26.3
Cedar Cove JV (1)	(5.1)		(4.4)
Matterhorn JV	109.0		63.9
Total investment in unconsolidated affiliates	$	135.3	$	85.8

____________________________

(1)As of March 31, 2023 and December 31, 2022, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheets.

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Employee Incentive Plans

3 Months Ended

Mar. 31, 2023

Share-Based Payment Arrangement [Abstract]

Employee Incentive Plans

(11) 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,
	2023		2022
Cost of unit-based compensation charged to operating expense	$	0.9	$	1.6
Cost of unit-based compensation charged to general and administrative expense	3.1		5.0
Total unit-based compensation expense	$	4.0	$	6.6
Amount of related income tax benefit recognized in net income (1)	$	0.9	$	1.6

____________________________

(1)For the three months ended March 31, 2023 and 2022, the amount of related income tax benefit recognized in net income excluded $6.5 million of income tax benefit and $2.0 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of unit-based awards.

b.Restricted Incentive Units

The 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, 2023 is provided below:

	Three Months Ended March 31, 2023
Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Unvested, beginning of period	6,775,186		$	5.89
Granted	1,244,629		10.85
Vested (1)	(2,201,569)		6.07
Forfeited	(55,101)		5.61
Unvested, end of period	5,763,145		$	6.90
Aggregate intrinsic value, end of period (in millions)	$	62.5

____________________________

(1)Vested units included 658,435 ENLC common 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, 2023 and 2022 is provided below (in millions):

	Three Months Ended March 31,
Restricted Incentive Units:	2023		2022
Aggregate intrinsic value of units vested	$	27.1	$	7.6
Fair value of units vested	$	13.4	$	10.7

As of March 31, 2023, there were $25.2 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.Performance Units

We grant 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, 2023
Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,979,154		$	6.44
Granted	420,128		11.67
Vested (1)	(899,919)		9.03
Non-vested, end of period	2,499,363		$	6.39
Aggregate intrinsic value, end of period (in millions)	$	27.1

____________________________

(1)Vested units included 668,829 ENLC common 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, 2023 and 2022 is provided below (in millions).

	Three Months Ended March 31,
Performance Units:	2023		2022
Aggregate intrinsic value of units vested	$	22.0	$	5.6
Fair value of units vested	$	8.1	$	11.0

As of March 31, 2023, there were $13.8 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 2.0 years.

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

Performance Units:	March 2023
Grant-date fair value	$	10.40
Beginning TSR Price	$	11.67
Risk-free interest rate	3.76		%
Volatility factor	64.00		%

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Derivatives

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(12) Derivatives

Interest Rate Swaps

In January 2023, we entered into a $400.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, SOFR-based borrowings. Under this arrangement, we pay a fixed interest rate of 3.8565% in exchange for SOFR-based variable interest through February 2026. Assets or liabilities related to this interest rate swap contract are included in the fair value of derivative assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract is recorded net as gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). We designated this interest rate swap as a cash flow hedge in accordance with ASC 815. There is no ineffectiveness related to this hedge.

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

	Three Months Ended March 31,
	2023		2022
Change in fair value of interest rate swaps	$	(1.6)	$	0.1
Tax benefit	0.4		—
Unrealized gain (loss) on designated cash flow hedge	$	(1.2)	$	0.1

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

	March 31, 2023		December 31, 2022
Fair value of derivative assets—current	$	3.1	$	—
Fair value of derivative liabilities—long-term	(4.7)		—
Net fair value of interest rate swaps	$	(1.6)	$	—

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,
	2023		2022
Interest expense (income)	$	(0.5)	$	0.1

We expect to recognize an additional $3.1 million of interest income out of accumulated other comprehensive income (loss) over the next twelve months.

Commodity Derivatives

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

	Three Months Ended March 31,
	2023		2022
Change in fair value of derivatives	$	(1.4)	$	(15.1)
Realized gain (loss) on derivatives	13.3		(16.1)
Gain (loss) on derivative activity	$	11.9	$	(31.2)

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

	March 31, 2023		December 31, 2022
Fair value of derivative assets—current	$	65.4	$	68.4
Fair value of derivative assets—long-term	13.6		2.9
Fair value of derivative liabilities—current	(41.1)		(42.9)
Fair value of derivative liabilities—long-term	(13.6)		(2.7)
Net fair value of commodity derivatives	$	24.3	$	25.7

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity derivatives that we held for price risk management purposes and the related physical offsets at March 31, 2023 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028.

Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	MMgals	(144.3)	$	9.1
Natural gas (short contracts)	Swaps and futures	Bbtu	(118.6)	37.4
Natural gas (long contracts)	Swaps and futures	Bbtu	89.3	(21.4)
Crude and condensate (short contracts)	Swaps and futures	MMbbls	(8.9)	4.3
Crude and condensate (long contracts)	Swaps and futures	MMbbls	1.2	(5.1)
Total fair value of commodity derivatives				$	24.3

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. Additionally, we have entered into FCDTCs that allow for netting of futures contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap and futures contracts, the maximum loss on our gross receivable position of $79.0 million as of March 31, 2023 would be reduced to $27.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs and the FCDTCs.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

(13) Fair Value Measurements

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

	Level 2
	March 31, 2023		December 31, 2022
Interest rate swaps (1)	$	(1.6)	$	—
Commodity derivatives (2)	$	24.3	$	25.7

____________________________

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

(2)The fair values of commodity derivatives 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, 2023				December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,828.0	$	4,559.2	$	4,723.5	$	4,385.9
Contingent consideration (2)(3)	$	6.2	$	6.2	$	5.5	$	5.5

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $36.1 million and $34.9 million as of March 31, 2023 and December 31, 2022, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable, if at all, 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.

(3)Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable, if at all, between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. 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, 2023 and December 31, 2022 were based on Level 2 inputs from third-party market quotations.

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Segment Information

3 Months Ended

Mar. 31, 2023

Segment Reporting [Abstract]

Segment Information

(14) Segment Information

We manage and report our activities primarily according to the geography and nature of activity. We have five reportable segments:

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

•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 Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and adjacent areas;

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

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, GCF in South Texas, and the Matterhorn JV in West Texas, as well as 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. See “Item 2. Management’s Discussion and Analysis of Financial Condition and

Results of Operations—Non-GAAP Financial Measures” for additional information. 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, 2023
Natural gas sales	$	129.3	$	131.8	$	66.8	$	14.5	$	—	$	342.4
NGL sales	0.4		857.9		8.6		(1.0)		—		865.9
Crude oil and condensate sales	186.7		56.6		24.7		—		—		268.0
Product sales	316.4		1,046.3		100.1		13.5		—		1,476.3
NGL sales—related parties	237.5		4.4		118.0		79.5		(439.4)		—
Crude oil and condensate sales—related parties	—		—		—		2.7		(2.7)		—
Product sales—related parties	237.5		4.4		118.0		82.2		(442.1)		—
Gathering and transportation	23.3		20.0		54.8		52.1		—		150.2
Processing	14.0		0.3		35.3		32.1		—		81.7
NGL services	—		27.8		—		—		—		27.8
Crude services	6.0		6.5		4.5		0.2		—		17.2
Other services	1.7		0.4		0.1		0.2		—		2.4
Midstream services	45.0		55.0		94.7		84.6		—		279.3
NGL services—related parties	—		—		—		0.6		(0.6)		—
Midstream services—related parties	—		—		—		0.6		(0.6)		—
Revenue from contracts with customers	598.9		1,105.7		312.8		180.9		(442.7)		1,755.6
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(457.1)		(973.9)		(194.0)		(89.6)		442.7		(1,271.9)
Realized gain (loss) on derivatives	(4.0)		7.2		2.0		8.1		—		13.3
Change in fair value of derivatives	6.3		(9.0)		(1.4)		2.7		—		(1.4)
Adjusted gross margin	144.1		130.0		119.4		102.1		—		495.6
Operating expenses	(48.1)		(33.6)		(24.7)		(26.0)		—		(132.4)
Segment profit	96.0		96.4		94.7		76.1		—		363.2
Depreciation and amortization	(40.0)		(38.3)		(51.9)		(28.8)		(1.4)		(160.4)
Gain on disposition of assets	—		0.1		0.2		0.1		—		0.4
General and administrative	—		—		—		—		(29.5)		(29.5)
Interest expense, net of interest income	—		—		—		—		(68.5)		(68.5)
Loss from unconsolidated affiliate investments	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	$	56.0	$	58.2	$	43.0	$	47.4	$	(99.5)	$	105.1
Capital expenditures	$	56.7	$	12.3	$	25.7	$	18.1	$	1.3	$	114.1

____________________________

(1)Includes related party cost of sales of $1.5 million for the three months ended March 31, 2023.

	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.

The table below represents information about segment assets as of March 31, 2023 and December 31, 2022 (in millions):

Segment Identifiable Assets:	March 31, 2023		December 31, 2022
Permian	$	2,643.6	$	2,661.4
Louisiana	2,172.4		2,310.7
Oklahoma	2,402.0		2,420.4
North Texas	1,064.8		1,094.6
Corporate (1)	263.6		163.9
Total identifiable assets	$	8,546.4	$	8,651.0

____________________________(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, 2023

Other Liabilities Disclosure [Abstract]

Other Information

(15) 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, 2023		December 31, 2022
Natural gas and NGLs inventory	$	70.0	$	147.1
Prepaid expenses and other	24.0		19.5
Other current assets	$	94.0	$	166.6

Other current liabilities:	March 31, 2023		December 31, 2022
Accrued interest	$	63.1	$	57.6
Accrued wages and benefits, including taxes	12.8		38.1
Accrued ad valorem taxes	13.8		32.0
Accrued settlement of mandatorily redeemable non-controlling interest (1)	—		10.5
Capital expenditure accruals	41.0		23.4
Short-term lease liability	27.9		26.2
Operating expense accruals	17.0		18.5
Other	20.3		23.3
Other current liabilities	$	195.9	$	229.6

____________________________

(1)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(16) 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.

One of our subsidiaries, EnLink Energy GP, LLC (“EnLink Energy”), was involved in industry-wide multi-district litigation arising out of Winter Storm Uri, pending in Harris County, Texas, in which multiple individual plaintiffs asserted 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. On January 26, 2023, the court dismissed the claims against the pipeline and other natural gas-related defendants in the multi-district litigation, including EnLink Energy. The court’s order was not appealed and the case is continuing without EnLink Energy and the other natural gas-related defendants. Subsequently, several suits were filed in February 2023 by individual plaintiffs (including one matter in which the plaintiffs seek to certify a class of Texas residents affected by Winter Storm Uri) and the alleged assignee of the claims of individual plaintiffs against 90 natural gas producers, pipelines, marketers, sellers, and traders, including EnLink Gas. All of these matters are currently pending in Harris County, Texas. Three of such suits, including the proposed class action, have been incorporated into the aforementioned industry-wide multi-district litigation. We believe the claims in these matters against EnLink Gas 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, 2023
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, 2022 filed with the Commission on February 15, 2023. 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, 2023

Accounting Policies [Abstract]

Summary of Contractually Committed Fees

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
2023 (remaining)	$	98.0
2024	114.9
2025	101.8
2026	100.7
2027	83.8
Thereafter	1,034.1
Total	$	1,533.3

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Acquisition (Tables)

3 Months Ended

Mar. 31, 2023

Business Combination and Asset Acquisition [Abstract]

Schedule of Assets Acquired and Liabilities Assumed

The following table presents the preliminary fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Consideration
Cash (including working capital payment)	$	100.9
Contingent consideration	1.3
Total consideration	$	102.2
Purchase price allocation (1)
Assets acquired:
Current assets	$	6.0
Property and equipment	97.1
Other assets, net (2)	0.9
Liabilities assumed:
Current liabilities	(1.4)
Other long-term liabilities (2)	(0.4)
Net assets acquired	$	102.2

____________________________

(1)The purchase price allocation was based on preliminary estimates and assumptions, which are subject to change within the measurement period (up to one year from the acquisition date), as we finalize the valuations of the assets acquired and liabilities assumed upon the closing of the acquisition.

(2)“Other assets, net” and “Other long-term liabilities” consist of the right-of-use assets and lease liabilities, respectively, obtained through the Central Oklahoma Acquisition.

Schedule of Asset Acquisition, Contingent Consideration

Contingent Consideration. The following table represents our change in carrying value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities for the periods presented (in millions):

	Three Months Ended March 31,
	2023		2022
Amarillo Rattler Acquisition contingent consideration
Contingent consideration liability, beginning of period (1)	$	4.2	$	6.9
Change in fair value	0.5		—
Contingent consideration liability, end of period	4.7		6.9
Central Oklahoma Acquisition contingent consideration
Contingent consideration liability, beginning of period (2)	1.3		—
Change in fair value	0.2		—
Contingent consideration liability, end of period	1.5		—
Total contingent consideration
Contingent consideration liability, beginning of period (1)(2)	5.5		6.9
Change in fair value	0.7		—
Contingent consideration liability, end of period	$	6.2	$	6.9

____________________________

(1)The contingent consideration for the Amarillo Rattler Acquisition was recorded on April 30, 2021.

(2)The contingent consideration for the Central Oklahoma Acquisition was recorded on December 19, 2022.

Schedule of Pro Forma Information

The following unaudited pro forma condensed consolidated financial information (in millions) for the three months ended March 31, 2022 gives effect to the Barnett Shale Acquisition on July 1, 2022 and the Central Oklahoma Acquisition on December 19, 2022 as if each of the acquisitions had occurred on January 1, 2022.

The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

	Three Months Ended March 31, 2022
Pro forma total revenues	$	2,256.9
Pro forma net income	$	75.2

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Intangible Assets (Tables)

3 Months Ended

Mar. 31, 2023

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, 2023
Customer relationships, beginning of period	$	1,844.8	$	(923.6)	$	921.2
Amortization expense	—		(31.9)		(31.9)
Customer relationships, end of period	$	1,844.8	$	(955.5)	$	889.3

Schedule of Amortization Expense

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

2023 (remaining)	$	95.7
2024	127.6
2025	110.2
2026	106.3
2027	106.3
Thereafter	343.2
Total	$	889.3

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Summary of Debt

As of March 31, 2023 and December 31, 2022, long-term debt consisted of the following (in millions):

	March 31, 2023						December 31, 2022
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Revolving Credit Facility due 2027 (1)	$	505.0	$	—	$	505.0	$	255.0	$	—	$	255.0
AR Facility due 2025 (2)	355.6		—		355.6		500.0		—		500.0
ENLK’s 4.40% Senior unsecured notes due 2024	97.9		—		97.9		97.9		—		97.9
ENLK’s 4.15% Senior unsecured notes due 2025	421.6		(0.1)		421.5		421.6		(0.1)		421.5
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.2)		490.8		491.0		(0.2)		490.8
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
ENLC’s 6.50% Senior unsecured notes due 2030	700.0		—		700.0		700.0		—		700.0
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.1)		444.9		450.0		(5.2)		444.8
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	$	4,869.8	$	(5.7)	4,864.1		$	4,764.2	$	(5.8)	4,758.4
Debt issuance cost (3)					(36.1)						(34.9)
Long-term debt, net of unamortized issuance cost					$	4,828.0					$	4,723.5

____________________________

(1)The effective interest rate was 6.9% and 6.5% at March 31, 2023 and December 31, 2022, respectively.

(2)The effective interest rate was 5.8% and 5.3% at March 31, 2023 and December 31, 2022, respectively.

(3)Net of accumulated amortization of $16.5 million and $15.1 million at March 31, 2023 and December 31, 2022, respectively.

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2023

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,
	2023		2022
Current income tax expense	$	(0.1)	$	(0.2)
Deferred income tax expense	(10.8)		(3.0)
Income tax expense	$	(10.9)	$	(3.2)

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,
	2023		2022
Expected income tax expense based on federal statutory rate	$	(14.5)	$	(8.1)
State income tax expense, net of federal benefit	(1.8)		(1.1)
Unit-based compensation (1)	6.5		(2.0)
Change in valuation allowance	—		7.1
Other	(1.1)		0.9
Income tax expense	$	(10.9)	$	(3.2)

____________________________

(1)Related to book-to-tax differences recorded upon the vesting of unit-based awards.

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Certain Provisions of the ENLK Partnership Agreement (Tables)

3 Months Ended

Mar. 31, 2023

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, 2023 and 2022 is provided below:

Declaration period	PIK Distribution	Cash distribution (in millions)		Date paid/payable
2023
Fourth Quarter of 2022	—	$	17.3	February 13, 2023
First Quarter of 2023	135,421	$	15.2	May 12, 2023
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022.

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

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Members' Equity (Tables)

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

GIP Repurchase Agreement

The following table summarizes our ENLC common unit repurchase activity for the periods presented (in millions, except for unit amounts):

	Three Months Ended March 31,
	2023		2022
Publicly held ENLC common units	2,207,305		2,093,842
ENLC common units held by GIP (1)	2,237,110		—
Total ENLC common units	4,444,415		2,093,842
Aggregate cost for publicly held ENLC common units	$	26.8	$	17.0
Aggregate cost for ENLC common units held by GIP	24.6		—
Total aggregate cost for ENLC common units	$	51.4	$	17.0
Average price paid per publicly held ENLC common unit	$	12.14	$	8.12
Average price paid per ENLC common unit held by GIP (2)	$	11.01	$	—

____________________________

(1)For the three months ended March 31, 2023, the 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 fourth quarter of 2022.

(2)For the three months ended March 31, 2023, the per unit price we paid to GIP was the average per unit price paid by us for publicly held ENLC common units repurchased, less broker commissions, during the fourth quarter of 2022.

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,
	2023		2022
Distributed earnings allocated to:
Common units (1)	$	58.6	$	54.4
Unvested unit-based awards (1)	0.9		1.1
Total distributed earnings	$	59.5	$	55.5
Undistributed loss allocated to:
Common units	$	(1.3)	$	(19.9)
Unvested unit-based awards	—		(0.4)
Total undistributed loss	$	(1.3)	$	(20.3)
Net income attributable to ENLC allocated to:
Common units	$	57.3	$	34.5
Unvested unit-based awards	0.9		0.7
Total net income attributable to ENLC	$	58.2	$	35.2
Net income attributable to ENLC per unit:
Basic	$	0.12	$	0.07
Diluted	$	0.12	$	0.07

____________________________

(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,
	2023	2022
Basic weighted average units outstanding:
Weighted average common units outstanding	468.9	484.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	468.9	484.0
Dilutive effect of unvested unit-based awards	4.4	6.6
Total weighted average diluted common units outstanding	473.3	490.6

Summary of Distribution Activity

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2023 and 2022, respectively, is provided below:

Declaration period	Distribution/unit		Date paid/payable
2023
Fourth Quarter of 2022	$	0.12500	February 13, 2023
First Quarter of 2023	$	0.12500	May 12, 2023
2022
Fourth Quarter of 2021	$	0.11250	February 11, 2022
First Quarter of 2022	$	0.11250	May 13, 2022

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Investment in Unconsolidated Affiliates (Tables)

3 Months Ended

Mar. 31, 2023

Equity Method Investments and Joint Ventures [Abstract]

Activity Related to Investment in Unconsolidated Affiliates

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

	Three Months Ended March 31,
	2023		2022
GCF
Contributions	$	6.2	$	—
Equity in loss	$	(1.1)	$	(0.7)
Cedar Cove JV
Distributions	$	(0.1)	$	(0.2)
Equity in loss	$	(0.6)	$	(0.4)
Matterhorn JV
Contributions	$	43.5	$	—
Equity in income	$	1.6	$	—
Total
Contributions	$	49.7	$	—
Distributions	$	(0.1)	$	(0.2)
Equity in loss	$	(0.1)	$	(1.1)

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2023 and December 31, 2022 (in millions):

	March 31, 2023		December 31, 2022
GCF	$	31.4	$	26.3
Cedar Cove JV (1)	(5.1)		(4.4)
Matterhorn JV	109.0		63.9
Total investment in unconsolidated affiliates	$	135.3	$	85.8

____________________________

(1)As of March 31, 2023 and December 31, 2022, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheets.

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Employee Incentive Plans (Tables)

3 Months Ended

Mar. 31, 2023

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,
	2023		2022
Cost of unit-based compensation charged to operating expense	$	0.9	$	1.6
Cost of unit-based compensation charged to general and administrative expense	3.1		5.0
Total unit-based compensation expense	$	4.0	$	6.6
Amount of related income tax benefit recognized in net income (1)	$	0.9	$	1.6

____________________________

(1)For the three months ended March 31, 2023 and 2022, the amount of related income tax benefit recognized in net income excluded $6.5 million of income tax benefit and $2.0 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of unit-based awards.

Schedule Of Restricted Stock Units Activity, ENLC

A summary of the restricted incentive unit activity for the three months ended March 31, 2023 is provided below:

	Three Months Ended March 31, 2023
Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Unvested, beginning of period	6,775,186		$	5.89
Granted	1,244,629		10.85
Vested (1)	(2,201,569)		6.07
Forfeited	(55,101)		5.61
Unvested, end of period	5,763,145		$	6.90
Aggregate intrinsic value, end of period (in millions)	$	62.5

____________________________(1)Vested units included 658,435 ENLC common 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, 2023 and 2022 is provided below (in millions):

	Three Months Ended March 31,
Restricted Incentive Units:	2023		2022
Aggregate intrinsic value of units vested	$	27.1	$	7.6
Fair value of units vested	$	13.4	$	10.7

Summary of Performance Units, ENLC

The following table presents a summary of the performance units:

	Three Months Ended March 31, 2023
Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,979,154		$	6.44
Granted	420,128		11.67
Vested (1)	(899,919)		9.03
Non-vested, end of period	2,499,363		$	6.39
Aggregate intrinsic value, end of period (in millions)	$	27.1

____________________________

(1)Vested units included 668,829 ENLC common 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, 2023 and 2022 is provided below (in millions).

	Three Months Ended March 31,
Performance Units:	2023		2022
Aggregate intrinsic value of units vested	$	22.0	$	5.6
Fair value of units vested	$	8.1	$	11.0

Summary of Grant-Date Fair Values

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

Performance Units:	March 2023
Grant-date fair value	$	10.40
Beginning TSR Price	$	11.67
Risk-free interest rate	3.76		%
Volatility factor	64.00		%

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Components of Gain (Loss) on Derivative Activity

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

	Three Months Ended March 31,
	2023		2022
Change in fair value of interest rate swaps	$	(1.6)	$	0.1
Tax benefit	0.4		—
Unrealized gain (loss) on designated cash flow hedge	$	(1.2)	$	0.1

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,
	2023		2022
Interest expense (income)	$	(0.5)	$	0.1

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

	Three Months Ended March 31,
	2023		2022
Change in fair value of derivatives	$	(1.4)	$	(15.1)
Realized gain (loss) on derivatives	13.3		(16.1)
Gain (loss) on derivative activity	$	11.9	$	(31.2)

Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps

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

	March 31, 2023		December 31, 2022
Fair value of derivative assets—current	$	3.1	$	—
Fair value of derivative liabilities—long-term	(4.7)		—
Net fair value of interest rate swaps	$	(1.6)	$	—

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

	March 31, 2023		December 31, 2022
Fair value of derivative assets—current	$	65.4	$	68.4
Fair value of derivative assets—long-term	13.6		2.9
Fair value of derivative liabilities—current	(41.1)		(42.9)
Fair value of derivative liabilities—long-term	(13.6)		(2.7)
Net fair value of commodity derivatives	$	24.3	$	25.7

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 derivatives that we held for price risk management purposes and the related physical offsets at March 31, 2023 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028.

Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	MMgals	(144.3)	$	9.1
Natural gas (short contracts)	Swaps and futures	Bbtu	(118.6)	37.4
Natural gas (long contracts)	Swaps and futures	Bbtu	89.3	(21.4)
Crude and condensate (short contracts)	Swaps and futures	MMbbls	(8.9)	4.3
Crude and condensate (long contracts)	Swaps and futures	MMbbls	1.2	(5.1)
Total fair value of commodity derivatives				$	24.3

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2023

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, 2023		December 31, 2022
Interest rate swaps (1)	$	(1.6)	$	—
Commodity derivatives (2)	$	24.3	$	25.7

____________________________

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

(2)The fair values of commodity derivatives 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, 2023				December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,828.0	$	4,559.2	$	4,723.5	$	4,385.9
Contingent consideration (2)(3)	$	6.2	$	6.2	$	5.5	$	5.5

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $36.1 million and $34.9 million as of March 31, 2023 and December 31, 2022, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable, if at all, 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.

(3)Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable, if at all, between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. 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, 2023

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. See “Item 2. Management’s Discussion and Analysis of Financial Condition and

Results of Operations—Non-GAAP Financial Measures” for additional information. 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, 2023
Natural gas sales	$	129.3	$	131.8	$	66.8	$	14.5	$	—	$	342.4
NGL sales	0.4		857.9		8.6		(1.0)		—		865.9
Crude oil and condensate sales	186.7		56.6		24.7		—		—		268.0
Product sales	316.4		1,046.3		100.1		13.5		—		1,476.3
NGL sales—related parties	237.5		4.4		118.0		79.5		(439.4)		—
Crude oil and condensate sales—related parties	—		—		—		2.7		(2.7)		—
Product sales—related parties	237.5		4.4		118.0		82.2		(442.1)		—
Gathering and transportation	23.3		20.0		54.8		52.1		—		150.2
Processing	14.0		0.3		35.3		32.1		—		81.7
NGL services	—		27.8		—		—		—		27.8
Crude services	6.0		6.5		4.5		0.2		—		17.2
Other services	1.7		0.4		0.1		0.2		—		2.4
Midstream services	45.0		55.0		94.7		84.6		—		279.3
NGL services—related parties	—		—		—		0.6		(0.6)		—
Midstream services—related parties	—		—		—		0.6		(0.6)		—
Revenue from contracts with customers	598.9		1,105.7		312.8		180.9		(442.7)		1,755.6
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(457.1)		(973.9)		(194.0)		(89.6)		442.7		(1,271.9)
Realized gain (loss) on derivatives	(4.0)		7.2		2.0		8.1		—		13.3
Change in fair value of derivatives	6.3		(9.0)		(1.4)		2.7		—		(1.4)
Adjusted gross margin	144.1		130.0		119.4		102.1		—		495.6
Operating expenses	(48.1)		(33.6)		(24.7)		(26.0)		—		(132.4)
Segment profit	96.0		96.4		94.7		76.1		—		363.2
Depreciation and amortization	(40.0)		(38.3)		(51.9)		(28.8)		(1.4)		(160.4)
Gain on disposition of assets	—		0.1		0.2		0.1		—		0.4
General and administrative	—		—		—		—		(29.5)		(29.5)
Interest expense, net of interest income	—		—		—		—		(68.5)		(68.5)
Loss from unconsolidated affiliate investments	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	$	56.0	$	58.2	$	43.0	$	47.4	$	(99.5)	$	105.1
Capital expenditures	$	56.7	$	12.3	$	25.7	$	18.1	$	1.3	$	114.1

____________________________

(1)Includes related party cost of sales of $1.5 million for the three months ended March 31, 2023.

	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.

Schedule of Segment Assets

The table below represents information about segment assets as of March 31, 2023 and December 31, 2022 (in millions):

Segment Identifiable Assets:	March 31, 2023		December 31, 2022
Permian	$	2,643.6	$	2,661.4
Louisiana	2,172.4		2,310.7
Oklahoma	2,402.0		2,420.4
North Texas	1,064.8		1,094.6
Corporate (1)	263.6		163.9
Total identifiable assets	$	8,546.4	$	8,651.0

____________________________(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, 2023

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, 2023		December 31, 2022
Natural gas and NGLs inventory	$	70.0	$	147.1
Prepaid expenses and other	24.0		19.5
Other current assets	$	94.0	$	166.6

Other current liabilities:	March 31, 2023		December 31, 2022
Accrued interest	$	63.1	$	57.6
Accrued wages and benefits, including taxes	12.8		38.1
Accrued ad valorem taxes	13.8		32.0
Accrued settlement of mandatorily redeemable non-controlling interest (1)	—		10.5
Capital expenditure accruals	41.0		23.4
Short-term lease liability	27.9		26.2
Operating expense accruals	17.0		18.5
Other	20.3		23.3
Other current liabilities	$	195.9	$	229.6

____________________________

(1)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries.

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General (Details)	3 Months Ended
	Mar. 31, 2023 Bcf / d processingPlant fractionator mi bbl
Related Party Transaction [Line Items]
Number of miles of pipeline | mi	13,600
Number of natural gas processing plants | processingPlant	26
Amount of processing capacity | Bcf / d	6.0
Number of fractionators | fractionator	7
Capacity of fractionators per day, barrels | bbl	320,000
ENLC | GIP Stetson II
Related Party Transaction [Line Items]
Membership interest in the General Partner as a percent	41.30%

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Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Mar. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,533.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	9 months
Remaining performance obligations	$ 98.0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 114.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 101.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 100.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 83.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	5 years
Remaining performance obligations	$ 1,034.1

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Significant Accounting Policies - Narrative (Details) $ in Millions	Jan. 31, 2023 USD ($)
Redeemable Non-Controlling Interest (Temporary Equity)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Redemption of the mandatorily redeemable non-controlling interest	$ 10.5

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Acquisition - Narrative (Details) - Central Oklahoma Acquisition	Dec. 19, 2022 MMcf / d plant mi
Business Acquisition [Line Items]
Number of miles of pipeline acquired | mi	900
Number of processing plants acquired | plant	2
Business combination, amount of processing capacity acquired | MMcf / d	280

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Acquisition - Fair Value Of Assets Received And Liabilities Assumed (Details) - Central Oklahoma Acquisition $ in Millions	Dec. 19, 2022 USD ($)
Consideration
Cash (including working capital payment)	$ 100.9
Contingent consideration	1.3
Total consideration	102.2
Assets acquired:
Current assets	6.0
Property and equipment	97.1
Other assets, net	0.9
Liabilities assumed:
Current liabilities	(1.4)
Other long-term liabilities	(0.4)
Net assets acquired	$ 102.2

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Acquisitions - Contingent Consideration (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Business Combination, Contingent Consideration, Liability [Roll Forward]
Contingent consideration liability, beginning of period	$ 5.5	$ 6.9
Change in fair value	0.7	0.0
Contingent consideration liability, end of period	6.2	6.9
Amarillo Rattler, LLC
Business Combination, Contingent Consideration, Liability [Roll Forward]
Contingent consideration liability, beginning of period	4.2	6.9
Change in fair value	0.5	0.0
Contingent consideration liability, end of period	4.7	6.9
Central Oklahoma Acquisition
Business Combination, Contingent Consideration, Liability [Roll Forward]
Contingent consideration liability, beginning of period	1.3	0.0
Change in fair value	0.2	0.0
Contingent consideration liability, end of period	$ 1.5	$ 0.0

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Acquisition - Pro Forma (Details) - Crestwood Gas Services Operating LLC $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($)
Business Acquisition [Line Items]
Pro forma total revenues	$ 2,256.9
Pro forma net income	$ 75.2

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Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ (31.9)	$ (32.8)
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	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, 2023	Mar. 31, 2022
Finite-lived Intangible Assets [Roll Forward]
Gross carrying amount, beginning balance	$ 1,844.8
Accumulated amortization, beginning balance	(923.6)
Net carrying amount, beginning balance	921.2
Amortization expense	(31.9)	$ (32.8)
Gross carrying amount, ending balance	1,844.8
Accumulated amortization, ending balance	(955.5)
Net carrying amount, ending balance	$ 889.3

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Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
2023	$ 95.7
2024	127.6
2025	110.2
2026	106.3
2027	106.3
Thereafter	343.2
Total	$ 889.3	$ 921.2

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Related Party Transactions (Details) - USD ($)		3 Months Ended
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	$ 1,271,900,000	$ 1,794,500,000
Accounts payable to related party		1,200,000		$ 2,500,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization		1,500,000	10,600,000
Accounts payable to related party		1,200,000		$ 2,500,000
GIP
Related Party Transaction [Line Items]
General and administrative expenses from transactions with related party		$ 0	$ 0

[1] Includes related party cost of sales of $1.5 million and $10.6 million for the three months ended March 31, 2023 and 2022, respectively.

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Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Debt Instrument
Outstanding Principal	$ 4,869.8	$ 4,764.2
Premium (Discount)	(5.7)	(5.8)
Long-Term Debt	4,864.1	4,758.4
Debt issuance costs	(36.1)	(34.9)
Long-term debt, net of unamortized issuance cost	4,828.0	4,723.5
Debt issuance cost accumulated amortization	16.5	15.1
Revolving Credit Facility Due 2027
Debt Instrument
Outstanding Principal	505.0	255.0
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 505.0	$ 255.0
Effective interest rate (as a percent)	6.90%	6.50%
AR Facility due 2025
Debt Instrument
Outstanding Principal	$ 355.6	$ 500.0
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 355.6	$ 500.0
Effective interest rate (as a percent)	5.80%	5.30%
4.40% Senior Notes due 2024
Debt Instrument
Outstanding Principal	$ 97.9	$ 97.9
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 97.9	97.9
Stated interest rate (as a percent)	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding Principal	$ 421.6	421.6
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 421.5	421.5
Stated interest rate (as a percent)	4.15%
4.85% Senior Unsecured Notes Due 2026
Debt Instrument
Outstanding Principal	$ 491.0	491.0
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 490.8	490.8
Stated interest rate (as a percent)	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 (as a percent)	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 (as a percent)	5.375%
6.50% Senior Notes due 2030
Debt Instrument
Outstanding Principal	$ 700.0	700.0
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 700.0	700.0
Stated interest rate (as a percent)	6.50%
5.60% 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 (as a percent)	5.60%
5.05% Senior Notes due 2045
Debt Instrument
Outstanding Principal	$ 450.0	450.0
Premium (Discount)	(5.1)	(5.2)
Long-Term Debt	$ 444.9	444.8
Stated interest rate (as a percent)	5.05%
5.45% Senior Notes due 2045
Debt Instrument
Outstanding Principal	$ 500.0	500.0
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9
Stated interest rate (as a percent)	5.45%

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Long-Term Debt - Narrative (Details) - USD ($)		3 Months Ended
	Aug. 31, 2022	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Debt Instrument
Increase (decrease) in accounts receivable		$ 589,400,000
Outstanding Principal		4,869,800,000		$ 4,764,200,000
Proceeds from borrowings		1,173,000,000	$ 500,000,000.0
Unsecured Debt
Debt Instrument
Debt repurchased	$ 700,000,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity		355,600,000
Accounts receivable securitization facility, outstanding amount		355,600,000
Letters of credit
Debt Instrument
Additional amount available (not to exceed)		1,400,000,000
Line of credit facility, fair value of amount outstanding		505,000,000
Letters of credit | Letter of Credit
Debt Instrument
Maximum borrowing capacity		500,000,000
Letters of credit | Letter of Credit | ENLC
Debt Instrument
Line of credit facility, fair value of amount outstanding		43,600,000
6.50% Senior Notes due 2030
Debt Instrument
Outstanding Principal		$ 700,000,000.0		700,000,000.0
Stated interest rate (as a percent)		6.50%
6.50% Senior Notes due 2030 | Unsecured Debt
Debt Instrument
Outstanding Principal	$ 300,000,000
Stated interest rate (as a percent)	6.50%
Percentage price of debt issued	99.00%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding Principal		$ 421,600,000		$ 421,600,000
Stated interest rate (as a percent)		4.15%
4.15% Senior Notes Due 2025 | Unsecured Debt
Debt Instrument
Proceeds from borrowings	$ 294,500,000

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Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.1)	$ (0.2)
Deferred income tax expense	(10.8)	(3.0)
Income tax expense	(10.9)	(3.2)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax expense based on federal statutory rate	(14.5)	(8.1)
State income tax expense, net of federal benefit	(1.8)	(1.1)
Unit-based compensation	6.5	(2.0)
Change in valuation allowance	0.0	7.1
Other	(1.1)	0.9
Income tax expense	$ (10.9)	$ (3.2)

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ 53.2	$ 42.7
Deferred tax assets	$ 731.9	$ 714.1

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Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions				1 Months Ended			3 Months Ended					12 Months Ended
	Dec. 15, 2022	May 13, 2022	Feb. 11, 2022	Feb. 28, 2023	Jan. 31, 2022	Dec. 31, 2021	Jun. 15, 2023	Mar. 31, 2023	Dec. 31, 2022	Mar. 31, 2022	Dec. 31, 2021	Dec. 31, 2022	Jun. 16, 2023
Redemption of Series B Preferred Units
Partnership agreement
Stock redeemed during period (in shares)					3,333,334
Total consideration paid					$ 50.5
Redemption price of preferred stock (as a percent)					101.00%
Distribution paid-in kind (in shares)									0
Cash distributions									$ 17.3
Redemption of Series B Preferred Units | Limited Partner
Partnership agreement
Distribution paid-in kind (in shares)								135,421		0	0
Cash distributions								$ 15.2		$ 17.5	$ 19.2
Redemption of Series B Preferred Units | Limited Partner | Distribution, Tranche One
Partnership agreement
Distributions preferred units			$ 17.3		$ 1.0	$ 0.9
Redemption of Series B Preferred Units | Limited Partner | Distribution, Tranche Two
Partnership agreement
Distributions preferred units		$ 17.2			$ 0.3
Redemption of Series B Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)								54,168,359	54,168,359			54,168,359
Preferred units, outstanding (in shares)								54,168,359	54,168,359			54,168,359
Price payable in cash, overage												$ 5.99
Repurchase of Series C Preferred Units
Partnership agreement
Stock redeemed during period (in shares)				4,500
Total consideration paid				$ 3.9
Redemption price of preferred stock (as a percent)				87.00%
Repurchase of Series C Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)								376,500	381,000			381,000
Preferred units, outstanding (in shares)								376,500	381,000			381,000
Redemption price	$ 1,000
Distributions to preferred unitholders								$ (8.4)		$ 0.0
Repurchase of Series C Preferred Units | EnLink Midstream Partners, LP | LIBOR
Partnership agreement
Variable floating rate percentage	4.11%
Repurchase of Series C Preferred Units | EnLink Midstream Partners, LP | Subsequent Event
Partnership agreement
Variable floating rate percentage							4.11%
Distribution rate per unit							9.051%
Distribution payable													$ 8.5

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Members' Equity - Narrative (Details) - USD ($)		3 Months Ended
	May 01, 2023	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Repurchase program, amount authorized				$ 200,000,000
Common units held (in shares)		4,444,415	2,093,842
Fair value adjustment related to redeemable non-controlling interest		$ 51,400,000	$ 17,000,000.0
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	1,910,877
Fair value adjustment related to redeemable non-controlling interest	$ 23,200,000
Shares repurchased, average cost per share (in dollars per share)	$ 12.12

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Members' Equity - IP Repurchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	4,444,415	2,093,842
Aggregate cost for common units	$ 51.4	$ 17.0
Public ENLC Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	2,207,305	2,093,842
Aggregate cost for common units	$ 26.8	$ 17.0
Average price of shares repurchased (in dollars per share)	$ 12.14	$ 8.12
ENCL Common Units Held by GIP
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	2,237,110	0
Aggregate cost for common units	$ 24.6	$ 0.0
Average price of shares repurchased (in dollars per share)	$ 11.01	$ 0

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Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Distributed earnings allocated to:
Total distributed earnings	$ 59.5	$ 55.5
Undistributed loss allocated to:
Total undistributed loss, basic	(1.3)	(20.3)
Total undistributed loss, diluted	(1.3)	(20.3)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	58.2	35.2
Total net income attributable to ENLC, diluted	$ 58.2	$ 35.2
Net income attributable to ENLC per unit:
Basic (in dollars per share)	$ 0.12	$ 0.07
Diluted (in dollars per share)	$ 0.12	$ 0.07
Unvested unit-based awards
Distributed earnings allocated to:
Total distributed earnings	$ 0.9	$ 1.1
Undistributed loss allocated to:
Total undistributed loss, basic	0.0	(0.4)
Total undistributed loss, diluted	0.0	(0.4)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	0.9	0.7
Total net income attributable to ENLC, diluted	0.9	0.7
Common units
Distributed earnings allocated to:
Total distributed earnings	58.6	54.4
Undistributed loss allocated to:
Total undistributed loss, basic	(1.3)	(19.9)
Total undistributed loss, diluted	(1.3)	(19.9)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	57.3	34.5
Total net income attributable to ENLC, diluted	$ 57.3	$ 34.5

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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, 2023	Mar. 31, 2022
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in shares)	468.9	484.0
Dilutive effect of unvested restricted units (in shares)	4.4	6.6
Total weighted average diluted common units outstanding (in shares)	473.3	490.6

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Members' Equity - Distributions (Details) - $ / shares	3 Months Ended
	Mar. 31, 2023	Dec. 31, 2022	Mar. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Distribution declared/unit (in dollars per share)	$ 0.12500	$ 0.12500	$ 0.11250	$ 0.11250

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Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Equity method investments
Contributions	$ 49.7	$ 0.0
Distributions	(0.1)	(0.2)
Equity in income (loss)	(0.1)	(1.1)
Total investment in unconsolidated affiliates	$ 140.4		$ 90.2
GCF
Equity method investments
Ownership interest	38.75%
Contributions	$ 6.2	0.0
Equity in income (loss)	$ (1.1)	(0.7)
Cedar Cove JV
Equity method investments
Ownership interest	30.00%
Distributions	$ (0.1)	(0.2)
Equity in income (loss)	$ (0.6)	(0.4)
Matterhorn JV
Equity method investments
Ownership interest	15.00%
Contributions	$ 43.5	0.0
Equity in income (loss)	1.6	$ 0.0
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	135.3		85.8
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	31.4		26.3
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	(5.1)		(4.4)
EnLink Midstream Partners, LP | Matterhorn JV
Equity method investments
Total investment in unconsolidated affiliates	$ 109.0		$ 63.9

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Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Allocation
Total unit-based compensation expense	$ 4.0	$ 6.6
Amount of related income tax benefit recognized in net income	0.9	1.6
Tax expense (benefit)	(6.5)	2.0
Restricted units
Allocation
Tax expense (benefit)	(6.5)	2.0
Cost of unit-based compensation charged to operating expense
Allocation
Total unit-based compensation expense	0.9	1.6
Cost of unit-based compensation charged to general and administrative expense
Allocation
Total unit-based compensation expense	$ 3.1	$ 5.0

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Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Unvested unit-based awards
Number of Units
Non-vested, beginning of period (in shares)	6,775,186
Granted (in shares)	1,244,629
Vested (in shares)	(2,201,569)
Forfeited (in shares)	(55,101)
Non-vested, end of period (in shares)	5,763,145
Aggregate intrinsic value, end of period	$ 62.5
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)	$ 5.89
Granted (in dollars per share)	10.85
Vested (in dollars per share)	6.07
Forfeited (in dollars per share)	5.61
Non-vested, end of period (in dollars per share)	$ 6.90
Units withheld for payroll taxes (in shares)	658,435
Aggregate intrinsic value of units vested	$ 27.1	$ 7.6
Fair value of units vested	13.4	10.7
Unrecognized compensation cost related to non-vested restricted incentive units	$ 25.2
Unrecognized compensation costs, weighted average period for recognition (in years)	2 years
Performance units
Number of Units
Non-vested, beginning of period (in shares)	2,979,154
Granted (in shares)	420,128
Vested (in shares)	(899,919)
Non-vested, end of period (in shares)	2,499,363
Aggregate intrinsic value, end of period	$ 27.1
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)	$ 6.44
Granted (in dollars per share)	11.67
Vested (in dollars per share)	9.03
Non-vested, end of period (in dollars per share)	$ 6.39
Units withheld for payroll taxes (in shares)	668,829
Aggregate intrinsic value of units vested	$ 22.0	5.6
Fair value of units vested	8.1	$ 11.0
Unrecognized compensation cost related to non-vested restricted incentive units	$ 13.8
Unrecognized compensation costs, weighted average period for recognition (in years)	2 years
Performance Units:
Beginning TSR Price (in dollars per share)	$ 10.40
Grant-date fair value (in dollars per share)	$ 11.67
Risk-free interest rate (as a percent)	3.76%
Volatility factor (as a percent)	64.00%
Performance units | Minimum
Performance Units:
Percent of units vesting (as a percent)	0.00%
Performance units | Maximum
Performance Units:
Percent of units vesting (as a percent)	200.00%

XML

Derivatives - Narrative (Details) - USD ($)	Mar. 31, 2023	Jan. 31, 2023
Derivatives
Derivative, notional amount		$ 400,000,000
Derivative, fixed interest rate		3.8565%
Interest expense out of accumulated other comprehensive loss over the next twelve months	$ 3,100,000
Commodity swaps
Derivatives
Maximum loss if counterparties fail to perform	79,000,000
Possible reduction in maximum loss if counterparties fail to perform	$ 27,500,000

XML

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Derivatives
Tax benefit		$ 0.4
Unrealized gain (loss) on designated cash flow hedge	[1]	(1.2)	$ 0.1
Fair value of derivative assets—current		68.5		$ 68.4
Fair value of derivative liabilities—long-term		(18.3)		(2.7)
Interest expense (income)		(0.5)	0.1
Interest rate swaps
Derivatives
Change in fair value of interest rate swaps		(1.6)	0.1
Tax benefit		0.4	0.0
Unrealized gain (loss) on designated cash flow hedge		(1.2)	$ 0.1
Fair value of derivative assets—current		3.1		0.0
Fair value of derivative liabilities—long-term		(4.7)		0.0
Net fair value of commodity derivatives		$ (1.6)		$ 0.0

[1] Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

XML

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Derivatives
Change in fair value of interest rate swaps	$ (1.4)	$ (15.1)
Gain (loss) on derivative activity	11.9	(31.2)
Commodity swaps
Derivatives
Change in fair value of interest rate swaps	(1.4)	(15.1)
Realized gain (loss) on derivatives	13.3	(16.1)
Gain (loss) on derivative activity	$ 11.9	$ (31.2)

XML

Derivatives - Fair Value of Commodity Swap Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Derivatives
Fair value of derivative assets—current	$ 68.5	$ 68.4
Fair value of derivative assets—long-term	13.6	2.9
Fair value of derivative liabilities—current	(41.1)	(42.9)
Fair value of derivative liabilities—long-term	(18.3)	(2.7)
Commodity swaps
Derivatives
Fair value of derivative assets—current	65.4	68.4
Fair value of derivative assets—long-term	13.6	2.9
Fair value of derivative liabilities—current	(41.1)	(42.9)
Fair value of derivative liabilities—long-term	(13.6)	(2.7)
Net fair value of commodity derivatives	$ 24.3	$ 25.7

XML

Derivatives - Commodity Swaps Additional Information (Details) - Commodity swaps gal in Millions, bbl in Millions, BTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) BTU bbl gal	Dec. 31, 2022 USD ($)
Derivatives
Net fair value of commodity derivatives	$ 24.3	$ 25.7
NGL | Short
Derivatives
Notional amount (in gallons or MMBLS) | gal	144.3
Net fair value of commodity derivatives	$ 9.1
Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | BTU	118.6
Net fair value of commodity derivatives	$ 37.4
Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | BTU	89.3
Net fair value of commodity derivatives	$ (21.4)
Crude and Condensate | Short
Derivatives
Notional amount (in gallons or MMBLS) | bbl	8.9
Net fair value of commodity derivatives	$ 4.3
Crude and Condensate | Long
Derivatives
Notional amount (in gallons or MMBLS) | bbl	1.2
Net fair value of commodity derivatives	$ (5.1)

XML

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Interest rate swaps
Fair Value
Net fair value of commodity derivatives	$ (1.6)	$ 0.0
Commodity swaps
Fair Value
Net fair value of commodity derivatives	24.3	25.7
Level 2 | Interest rate swaps | Recurring
Fair Value
Net fair value of commodity derivatives	(1.6)	0.0
Level 2 | Commodity swaps | Recurring
Fair Value
Net fair value of commodity derivatives	$ 24.3	$ 25.7

XML

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022	Apr. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Fair Value
Contingent consideration	$ 6.2	$ 5.5		$ 6.9	$ 6.9
Debt issuance costs	36.1	34.9
Amarillo Rattler, LLC
Fair Value
Contingent consideration	4.7	4.2		$ 6.9	$ 6.9
Business combination, maximum earnout			$ 15.0
Carrying Value
Fair Value
Long-term debt	4,828.0	4,723.5
Contingent consideration	6.2	5.5
Fair Value
Fair Value
Long-term debt	4,559.2	4,385.9
Contingent consideration	$ 6.2	$ 5.5

XML

Segment Information - Narrative (Details)	3 Months Ended
	Mar. 31, 2023 segment
Segment Reporting [Abstract]
Number of reportable segments	5

XML

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2023	Mar. 31, 2022
Segment Reporting
Revenue from contracts with customers		$ 1,755.6	$ 2,258.9
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	(1,271.9)	(1,794.5)
Realized gain (loss) on derivatives		13.3	(16.1)
Change in fair value of interest rate swaps		(1.4)	(15.1)
Adjusted gross margin		495.6	433.2
Operating expenses		(132.4)	(120.9)
Segment profit		363.2	312.3
Depreciation and amortization		(160.4)	(152.9)
Gain (loss) on disposition of assets		0.4	(5.1)
General and administrative		(29.5)	(29.0)
Interest expense, net of interest income		(68.5)	(55.1)
Loss from unconsolidated affiliate investments		(0.1)	(1.1)
Other income		0.0	0.1
Income before non-controlling interest and income taxes		105.1	69.2
Capital expenditures		114.1	60.0
Related parties amount in cost of sales		1.5	10.6
Permian
Segment Reporting
Revenue from contracts with customers		598.9	893.3
Cost of sales, exclusive of operating expenses and depreciation and amortization		(457.1)	(766.7)
Realized gain (loss) on derivatives		(4.0)	(2.4)
Change in fair value of interest rate swaps		6.3	(5.9)
Adjusted gross margin		144.1	118.3
Operating expenses		(48.1)	(45.3)
Segment profit		96.0	73.0
Depreciation and amortization		(40.0)	(36.7)
Gain (loss) on disposition of assets		0.0	0.0
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Loss from unconsolidated affiliate investments		0.0	0.0
Other income			0.0
Income before non-controlling interest and income taxes		56.0	36.3
Capital expenditures		56.7	34.2
Louisiana
Segment Reporting
Revenue from contracts with customers		1,105.7	1,524.4
Cost of sales, exclusive of operating expenses and depreciation and amortization		(973.9)	(1,388.7)
Realized gain (loss) on derivatives		7.2	(6.6)
Change in fair value of interest rate swaps		(9.0)	(5.6)
Adjusted gross margin		130.0	123.5
Operating expenses		(33.6)	(33.0)
Segment profit		96.4	90.5
Depreciation and amortization		(38.3)	(35.5)
Gain (loss) on disposition of assets		0.1	0.2
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Loss from unconsolidated affiliate investments		0.0	0.0
Other income			0.0
Income before non-controlling interest and income taxes		58.2	55.2
Capital expenditures		12.3	5.7
Oklahoma
Segment Reporting
Revenue from contracts with customers		312.8	394.4
Cost of sales, exclusive of operating expenses and depreciation and amortization		(194.0)	(276.8)
Realized gain (loss) on derivatives		2.0	(3.7)
Change in fair value of interest rate swaps		(1.4)	(7.1)
Adjusted gross margin		119.4	106.8
Operating expenses		(24.7)	(21.0)
Segment profit		94.7	85.8
Depreciation and amortization		(51.9)	(50.9)
Gain (loss) on disposition of assets		0.2	0.2
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Loss from unconsolidated affiliate investments		0.0	0.0
Other income			0.0
Income before non-controlling interest and income taxes		43.0	35.1
Capital expenditures		25.7	15.4
North Texas
Segment Reporting
Revenue from contracts with customers		180.9	241.9
Cost of sales, exclusive of operating expenses and depreciation and amortization		(89.6)	(157.4)
Realized gain (loss) on derivatives		8.1	(3.4)
Change in fair value of interest rate swaps		2.7	3.5
Adjusted gross margin		102.1	84.6
Operating expenses		(26.0)	(21.6)
Segment profit		76.1	63.0
Depreciation and amortization		(28.8)	(28.4)
Gain (loss) on disposition of assets		0.1	(5.5)
General and administrative		0.0	0.0
Interest expense, net of interest income		0.0	0.0
Loss from unconsolidated affiliate investments		0.0	0.0
Other income			0.0
Income before non-controlling interest and income taxes		47.4	29.1
Capital expenditures		18.1	3.1
Corporate
Segment Reporting
Revenue from contracts with customers		(442.7)	(795.1)
Cost of sales, exclusive of operating expenses and depreciation and amortization		442.7	795.1
Realized gain (loss) on derivatives		0.0	0.0
Change in fair value of interest rate swaps		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)	(1.4)
Gain (loss) on disposition of assets		0.0	0.0
General and administrative		(29.5)	(29.0)
Interest expense, net of interest income		(68.5)	(55.1)
Loss from unconsolidated affiliate investments		(0.1)	(1.1)
Other income			0.1
Income before non-controlling interest and income taxes		(99.5)	(86.5)
Capital expenditures		1.3	1.6
Product sales
Segment Reporting
Revenue from contracts with customers		1,476.3	2,043.9
Product sales | Permian
Segment Reporting
Revenue from contracts with customers		316.4	467.6
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers		1,046.3	1,436.9
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		100.1	114.1
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers		13.5	25.3
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Natural gas sales
Segment Reporting
Revenue from contracts with customers		342.4	508.8
Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers		129.3	195.6
Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers		131.8	211.5
Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		66.8	76.3
Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers		14.5	25.4
Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
NGL sales
Segment Reporting
Revenue from contracts with customers		865.9	1,154.5
NGL sales | Permian
Segment Reporting
Revenue from contracts with customers		0.4	0.0
NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers		857.9	1,151.5
NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		8.6	3.1
NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers		(1.0)	(0.1)
NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers		268.0	380.6
Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers		186.7	272.0
Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers		56.6	73.9
Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		24.7	34.7
Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers		0.0	0.0
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		237.5	399.8
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		4.4	36.9
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		118.0	208.4
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		82.2	149.9
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(442.1)	(795.0)
NGL sales—related parties
Segment Reporting
Revenue from contracts with customers		0.0	0.0
NGL sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers		237.5	399.8
NGL sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		4.4	36.9
NGL sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		118.0	208.1
NGL sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		79.5	146.9
NGL sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(439.4)	(791.7)
Crude oil and condensate sales—related parties
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Crude oil and condensate sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Crude oil and condensate sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Crude oil and condensate sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0	0.3
Crude oil and condensate sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		2.7	3.0
Crude oil and condensate sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(2.7)	(3.3)
Midstream services
Segment Reporting
Revenue from contracts with customers		279.3	215.0
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers		45.0	25.9
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers		55.0	50.5
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers		94.7	71.9
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers		84.6	66.7
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Gathering and transportation
Segment Reporting
Revenue from contracts with customers		150.2	111.4
Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers		23.3	13.6
Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers		20.0	16.3
Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers		54.8	42.7
Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers		52.1	38.8
Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Processing
Segment Reporting
Revenue from contracts with customers		81.7	61.3
Processing | Permian
Segment Reporting
Revenue from contracts with customers		14.0	7.8
Processing | Louisiana
Segment Reporting
Revenue from contracts with customers		0.3	0.5
Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers		35.3	25.4
Processing | North Texas
Segment Reporting
Revenue from contracts with customers		32.1	27.6
Processing | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
NGL services
Segment Reporting
Revenue from contracts with customers		27.8	23.9
NGL services | Permian
Segment Reporting
Revenue from contracts with customers		0.0	0.0
NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers		27.8	23.9
NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0	0.0
NGL services | North Texas
Segment Reporting
Revenue from contracts with customers		0.0	0.0
NGL services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Crude services
Segment Reporting
Revenue from contracts with customers		17.2	17.6
Crude services | Permian
Segment Reporting
Revenue from contracts with customers		6.0	4.3
Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers		6.5	9.4
Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers		4.5	3.7
Crude services | North Texas
Segment Reporting
Revenue from contracts with customers		0.2	0.2
Crude services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Other services
Segment Reporting
Revenue from contracts with customers		2.4	0.8
Other services | Permian
Segment Reporting
Revenue from contracts with customers		1.7	0.2
Other services | Louisiana
Segment Reporting
Revenue from contracts with customers		0.4	0.4
Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1	0.1
Other services | North Texas
Segment Reporting
Revenue from contracts with customers		0.2	0.1
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		0.0	0.1
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0	0.0
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0.6	0.0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(0.6)	(0.1)
NGL services—related parties
Segment Reporting
Revenue from contracts with customers		0.0
NGL services—related parties | Permian
Segment Reporting
Revenue from contracts with customers		0.0
NGL services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0.0
NGL services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.0
NGL services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0.6
NGL services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		$ (0.6)
Other services—related parties
Segment Reporting
Revenue from contracts with customers			0.0
Other services—related parties | Permian
Segment Reporting
Revenue from contracts with customers			0.0
Other services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers			0.1
Other services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers			0.0
Other services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers			0.0
Other services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers			$ (0.1)

[1] Includes related party cost of sales of $1.5 million and $10.6 million for the three months ended March 31, 2023 and 2022, respectively.

XML

Segment Information - Assets (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Segment Reporting
Total identifiable assets	$ 8,546.4	$ 8,651.0
Permian
Segment Reporting
Total identifiable assets	2,643.6	2,661.4
Louisiana
Segment Reporting
Total identifiable assets	2,172.4	2,310.7
Oklahoma
Segment Reporting
Total identifiable assets	2,402.0	2,420.4
North Texas
Segment Reporting
Total identifiable assets	1,064.8	1,094.6
Corporate
Segment Reporting
Total identifiable assets	$ 263.6	$ 163.9

XML

Other Information (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Other current assets:
Natural gas and NGLs inventory	$ 70.0	$ 147.1
Prepaid expenses and other	24.0	19.5
Other current assets	94.0	166.6
Other current liabilities:
Accrued interest	63.1	57.6
Accrued wages and benefits, including taxes	12.8	38.1
Accrued ad valorem taxes	13.8	32.0
Accrued settlement Of mandatorily redeemable non-controlling interest	0.0	10.5
Capital expenditure accruals	41.0	23.4
Short-term lease liability	27.9	26.2
Operating expense accruals	17.0	18.5
Other	20.3	23.3
Other current liabilities	$ 195.9	$ 229.6

XML

Commitments and Contingencies - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) claim defendant
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
Number of defendants | defendant	350
Filed cases, over	150
Third party claims, number	90