EnLink Midstream (ENLC) 10-Q 2 Aug 23 2023 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2023	Jul. 27, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 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)		461,497,730
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2023
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Jun. 30, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents		$ 54.8	$ 22.6
Accounts receivable:
Trade receivables	[1]	82.6	89.2
Accrued revenue and other		459.3	636
Fair value of derivative assets		83.8	68.4
Other current assets		101.3	166.6
Total current assets		781.8	982.8
Property and equipment, net of accumulated depreciation of $5,026.1 and $4,774.5, respectively		6,503.9	6,556
Intangible assets, net of accumulated amortization of $987.4 and $923.6, respectively		857.4	921.2
Investment in unconsolidated affiliates		134.3	90.2
Fair value of derivative assets		18.3	2.9
Other assets, net		104.2	97.9
Total assets		8,399.9	8,651
Current liabilities:
Accounts payable and drafts payable		101.2	126.9
Accrued gas, NGLs, condensate, and crude oil purchases	[2]	314.6	476
Fair value of derivative liabilities		49.2	42.9
Current maturities of long-term debt		97.9	0
Other current liabilities		238.8	229.6
Total current liabilities		801.7	875.4
Long-term debt, net of unamortized issuance cost		4,640.9	4,723.5
Other long-term liabilities		92.9	94
Deferred tax liability, net		72.8	42.7
Fair value of derivative liabilities		17.4	2.7
Members’ equity:
Members’ equity (462,025,317 and 468,980,630 units issued and outstanding, respectively)		1,156.1	1,306.4
Accumulated other comprehensive income		4.5	0
Non-controlling interest		1,613.6	1,606.3
Total members’ equity		2,774.2	2,912.7
Commitments and contingencies (Note 16)
Total liabilities and members’ equity		$ 8,399.9	$ 8,651
[1]There was no allowance for bad debt at June 30, 2023. Includes allowance for bad debt of $0.1 million at December 31, 2022.[2]Includes related party accounts payable balances of $0.3 million and $2.5 million at June 30, 2023 and December 31, 2022, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
ASSETS
Property and equipment, accumulated depreciation	$ 5,026.1	$ 4,774.5
Intangible assets, accumulated amortization	$ 987.4	$ 923.6
Members’ equity:
Common units issued (in shares)	462,025,317	468,980,630
Common units outstanding (in shares)	468,980,630	462,025,317
Allowance for bad debt	$ 0	$ 0.1
Accounts payable, current	101.2	126.9
Product sales—related parties
Members’ equity:
Accounts payable, current	$ 0.3	$ 2.5

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Revenues:
Revenue from contracts with customers		$ 1,518.8	$ 2,596.1	$ 3,274.4	$ 4,855
Revenue, Product and Service [Extensible Enumeration]		Midstream service	Midstream service	Midstream service	Midstream service
Gain (loss) on derivative activity		$ 11.3	$ 4.5	$ 23.2	$ (26.7)
Total revenues		1,530.1	2,600.6	3,297.6	4,828.3
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	$ 1,019	$ 2,105.1	$ 2,290.9	$ 3,899.6
Cost, Product and Service [Extensible Enumeration]		Midstream service	Midstream service	Midstream service	Midstream service
Operating expenses		$ 136.8	$ 128.9	$ 269.2	$ 249.8
Depreciation and amortization		165.3	159	325.7	311.9
(Gain) loss on disposition of assets		(0.8)	(0.4)	(1.2)	4.7
General and administrative		27.9	28.4	57.4	57.4
Total operating costs and expenses		1,348.2	2,421	2,942	4,523.4
Operating income		181.9	179.6	355.6	304.9
Other income (expense):
Interest expense, net of interest income		(68.8)	(55.5)	(137.3)	(110.6)
Gain on extinguishment of debt		0	(0.5)	0	(0.5)
Loss from unconsolidated affiliate investments		(4.6)	(1.2)	(4.7)	(2.3)
Other income		0.4	0.2	0.4	0.3
Total other expense		(73)	(57)	(141.6)	(113.1)
Income before non-controlling interest and income taxes		108.9	122.6	214	191.8
Income tax benefit (expense)		(19)	1.3	(29.9)	(1.9)
Net income		89.9	123.9	184.1	189.9
Net income attributable to non-controlling interest		35.6	38.6	71.6	69.4
Net income attributable to ENLC		$ 54.3	$ 85.3	$ 112.5	$ 120.5
Net income attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ 0.12	$ 0.18	$ 0.24	$ 0.25
Diluted common unit (in dollars per share)		$ 0.12	$ 0.17	$ 0.24	$ 0.25
Product sales
Revenues:
Revenue from contracts with customers		$ 1,239.3	$ 2,370.5	$ 2,715.6	$ 4,414.4
Midstream service
Revenues:
Revenue from contracts with customers	[2]	$ 279.5	$ 225.6	$ 558.8	$ 440.6
[1]Includes related party cost of sales of $2.5 million and $9.1 million for the three months ended June 30, 2023 and 2022, respectively, and $4.0 million and $19.7 million for the six months ended June 30, 2023 and 2022, respectively.[2]Includes related party revenue of $0.6 million and $1.3 million for the three and six months ended June 30, 2023, respectively. We did not have related party revenue for the three and six months ended June 30, 2022.

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Revenue from contracts with customers		$ 1,518.8	$ 2,596.1	$ 3,274.4	$ 4,855
Cost of goods and services sold	[1]	1,019	2,105.1	2,290.9	3,899.6
Product sales—related parties
Revenue from contracts with customers		0.6	0	1.3	0
Cost of goods and services sold		2.5	9.1	4	19.7
Midstream service
Revenue from contracts with customers	[2]	$ 279.5	$ 225.6	$ 558.8	$ 440.6
[1]Includes related party cost of sales of $2.5 million and $9.1 million for the three months ended June 30, 2023 and 2022, respectively, and $4.0 million and $19.7 million for the six months ended June 30, 2023 and 2022, respectively.[2]Includes related party revenue of $0.6 million and $1.3 million for the three and six months ended June 30, 2023, respectively. We did not have related party revenue for the three and six months ended June 30, 2022.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2023		Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Statement of Comprehensive Income [Abstract]
Net income		$ 89.9		$ 123.9	$ 184.1	$ 189.9
Unrealized gain (loss) on designated cash flow hedge	[1]	5.7	[2]	0	4.5	0.1
Comprehensive income		95.6		123.9	188.6	190
Comprehensive income attributable to non-controlling interest		35.6		38.6	71.6	69.4
Comprehensive income attributable to ENLC		$ 60		$ 85.3	$ 117	$ 120.6
[1]Includes tax expense of $1.8 million and $1.4 million for the three and six months ended June 30, 2023, respectively.[2]Includes tax expense of $1.8 million for the three months ended June 30, 2023.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2023
Statement of Comprehensive Income [Abstract]
Tax expense (benefit)	$ 1.8	$ (0.4)	$ 1.4

Consolidated Statement of Chang

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		$ 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)		(56.4)		(34.6)
Unrealized gain (loss) on designated cash flow hedge		0.1			0.1
Repurchase of Preferred Units						(50.5)
Common units repurchased		(17)		$ (17)
Common units repurchased (in shares)				(2,100,000)
Net income		66		$ 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, ending balance (in shares) at Mar. 31, 2022				483,400,000
Member equity, beginning balance at Dec. 31, 2021		2,987		$ 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
Unrealized gain (loss) on designated cash flow hedge	[1]	0.1
Repurchase of Preferred Units		(50.5)
Common units repurchased		$ (50.7)
Common units repurchased (in shares)		(5,690,307)
Member equity, end balance at Jun. 30, 2022		$ 2,906		$ 1,293.3	(1.3)	1,614
Units outstanding, ending balance (in shares) at Jun. 30, 2022				479,800,000
Member equity, beginning balance at Mar. 31, 2022		2,905.8		$ 1,291.5	(1.3)	1,615.6
Units outstanding, beginning balance (in shares) at Mar. 31, 2022				483,400,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(0.2)		$ (0.2)
Unit-based compensation		5.7		5.7
Contributions from non-controlling interests		2				2
Distributions		(97.5)		(55.3)		(42.2)
Unrealized gain (loss) on designated cash flow hedge	[1]	0
Common units repurchased		$ (33.7)		$ (33.7)
Common units repurchased (in shares)		(3,596,465)		(3,600,000)
Net income		$ 123.9		$ 85.3		38.6
Member equity, end balance at Jun. 30, 2022		2,906		$ 1,293.3	(1.3)	1,614
Units outstanding, ending balance (in shares) at Jun. 30, 2022				479,800,000
Member equity, beginning balance at Dec. 31, 2022		$ 2,912.7		$ 1,306.4	0	1,606.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2022		468,980,630		469,000,000
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		$ 4
Contributions from non-controlling interests		8.4				8.4
Distributions		(104.1)		(61.7)		(42.4)
Unrealized gain (loss) on designated cash flow hedge	[2]	(1.2)			(1.2)
Repurchase of Preferred Units		(3.9)				(3.9)
Common units repurchased		(51.4)		$ (51.4)
Common units repurchased (in shares)				(4,400,000)
Net income		94.2		$ 58.2		36
Member equity, end balance at Mar. 31, 2023		2,841.9		$ 1,238.7	(1.2)	1,604.4
Units outstanding, ending balance (in shares) at Mar. 31, 2023				467,100,000
Member equity, beginning balance at Dec. 31, 2022		$ 2,912.7		$ 1,306.4	0	1,606.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2022		468,980,630		469,000,000
Increase (Decrease) in Members' Equity
Unrealized gain (loss) on designated cash flow hedge	[1]	$ 4.5
Common units repurchased		$ (107.5)
Common units repurchased (in shares)		(9,585,796)
Member equity, end balance at Jun. 30, 2023		$ 2,774.2		$ 1,156.1	4.5	1,613.6
Units outstanding, ending balance (in shares) at Jun. 30, 2023		462,025,317		462,000,000
Member equity, beginning balance at Mar. 31, 2023		$ 2,841.9		$ 1,238.7	(1.2)	1,604.4
Units outstanding, beginning balance (in shares) at Mar. 31, 2023				467,100,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(0.1)		$ (0.1)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)				100,000
Unit-based compensation		4.5		$ 4.5
Contributions from non-controlling interests		13.7				13.7
Distributions		(98.6)		(58.5)		(40.1)
Unrealized gain (loss) on designated cash flow hedge	[3]	5.7	[1]		5.7
Adjustment related to the redemption of the mandatorily redeemable non-controlling interest	[4]	0.8		0.8
Common units repurchased		$ (56.1)		$ (56.1)
Common units repurchased (in shares)		(5,141,381)		(5,200,000)
Common unit repurchases	[5]	$ (27.5)		$ (27.5)
Net income		89.9		54.3		35.6
Member equity, end balance at Jun. 30, 2023		$ 2,774.2		$ 1,156.1	$ 4.5	$ 1,613.6
Units outstanding, ending balance (in shares) at Jun. 30, 2023		462,025,317		462,000,000
[1]Includes tax expense of $1.8 million and $1.4 million for the three and six months ended June 30, 2023, respectively.[2]Includes tax benefit of $0.4 million for the three months ended March 31, 2023.[3]Includes tax expense of $1.8 million for the three months ended June 30, 2023.[4]Relates to book-to-tax differences recorded upon the settlement of the mandatorily redeemable non-controlling interest.[5]Relates to the repurchase of ENLC common units held by GIP on July 31, 2023. For additional information, see “Note 9—Members’ Equity.”

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2023
Statement of Stockholders' Equity [Abstract]
Tax expense (benefit)	$ 1.8	$ (0.4)	$ 1.4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022
Cash flows from operating activities:
Net income	$ 184.1	$ 189.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	325.7	311.9
Utility credits redeemed	1.5	11.6
Deferred income tax expense	29.6	1.2
(Gain) loss on disposition of assets	(1.2)	4.7
Non-cash unit-based compensation	8.5	12.3
Non-cash gain on derivatives recognized in net income	(3.9)	(18.6)
Amortization of debt issuance costs and net discount of senior unsecured notes	3.3	2.6
Loss from unconsolidated affiliate investments	4.7	2.3
Other operating activities	0.8	(1.4)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	183.1	(226.7)
Natural gas and NGLs inventory, prepaid expenses, and other	66.6	(83.2)
Accounts payable, accrued product purchases, and other accrued liabilities	(215)	276
Net cash provided by operating activities	587.8	482.6
Cash flows from investing activities:
Additions to property and equipment	(203.1)	(124.1)
Contributions to unconsolidated affiliate investments	(49.7)	(26.6)
Other investing activities	3.7	1.4
Net cash used in investing activities	(249.1)	(149.3)
Cash flows from financing activities:
Proceeds from borrowings	2,004.1	1,135
Repayments on borrowings	(1,989)	(1,177)
Payment of installment payable for the Amarillo Rattler Acquisition	0	(10)
Distributions to members	(120.2)	(111.7)
Distributions to non-controlling interests	(82.5)	(76.8)
Payment to redeem mandatorily redeemable non-controlling interest	(10.5)	0
Contributions from non-controlling interests	22.1	9.3
Common unit repurchases	(107.5)	(50.7)
Conversion of unit-based awards for common units, net of units withheld for taxes	(16.9)	(4.4)
Other financing activities	(2.2)	(4.6)
Net cash used in financing activities	(306.5)	(341.4)
Net increase (decrease) in cash and cash equivalents	32.2	(8.1)
Cash and cash equivalents, beginning of period	22.6	26.2
Cash and cash equivalents, end of period	54.8	18.1
Supplemental disclosures of cash flow information:
Cash paid for interest	131.1	107.8
Cash paid for income taxes	1	0.8
Non-cash investing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	11.6	15.3
Non-cash accrual of property and equipment	15.7	(1.6)
Redemption of Series B Preferred Units
Cash flows from financing activities:
Redemption of Series B Preferred Units	0	(50.5)
Repurchase of Series C Preferred Units
Cash flows from financing activities:
Redemption of Series B Preferred Units	$ (3.9)	$ 0

General

General	6 Months Ended
	Jun. 30, 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 June 30, 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 June 30, 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.

Significant Accounting Policies

Significant Accounting Policies	6 Months Ended
	Jun. 30, 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) $ 76.6 2024 127.5 2025 110.4 2026 115.0 2027 98.1 Thereafter 1,120.1 Total $ 1,647.7 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.

Acquisition

Acquisition	6 Months Ended
	Jun. 30, 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 Six Months Ended June 30, 2023 2022 2023 2022 Amarillo Rattler Acquisition contingent consideration Contingent consideration liability, beginning of period (1) $ 4.7 $ 6.9 $ 4.2 $ 6.9 Change in fair value (0.1) 0.3 0.4 0.3 Contingent consideration liability, end of period $ 4.6 $ 7.2 $ 4.6 $ 7.2 Central Oklahoma Acquisition contingent consideration Contingent consideration liability, beginning of period (2) $ 1.5 $ — $ 1.3 $ — Change in fair value 0.3 — 0.5 — Contingent consideration liability, end of period $ 1.8 $ — $ 1.8 $ — Total contingent consideration Contingent consideration liability, beginning of period (1)(2) $ 6.2 $ 6.9 $ 5.5 $ 6.9 Change in fair value 0.2 0.3 0.9 0.3 Contingent consideration liability, end of period $ 6.4 $ 7.2 $ 6.4 $ 7.2 ____________________________ (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 and Six Months Ended June 30, 2022 The following unaudited pro forma condensed consolidated financial information (in millions) for the three and six months ended June 30, 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 Six Months Ended Pro forma total revenues $ 2,635.5 $ 4,892.4 Pro forma net income $ 139.2 $ 214.4

Intangible Assets

Intangible Assets	6 Months Ended
	Jun. 30, 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 Six Months Ended June 30, 2023 Customer relationships, beginning of period $ 1,844.8 $ (923.6) $ 921.2 Amortization expense — (63.8) (63.8) Customer relationships, end of period $ 1,844.8 $ (987.4) $ 857.4 Amortization expense was $31.9 million for each of the three months ended June 30, 2023 and 2022 and $63.8 million and $64.7 million for the six months ended June 30, 2023 and 2022, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2023 (remaining) $ 63.8 2024 127.6 2025 110.2 2026 106.3 2027 106.3 Thereafter 343.2 Total $ 857.4

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2023
Related Party Transactions [Abstract]
Related Party Transactions	(5) Related Party Transactions (a) Transactions with Cedar Cove JV For the three and six months ended June 30, 2023, we recorded revenue of $0.6 million and $1.3 million, respectively, related to the receipt of residue gas and NGLs from the Cedar Cove JV. For each of the three and six months ended June 30, 2022, we did not record any revenue related to the receipt of residue gas and NGLs from the Cedar Cove JV. For the three and six months ended June 30, 2023, we recorded cost of sales of $2.5 million and $4.0 million, respectively, and for the three and six months ended June 30, 2022, we recorded cost of sales of $9.1 million and $19.7 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 $0.3 million and $2.5 million at June 30, 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 and six months ended June 30, 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.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2023
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt As of June 30, 2023 and December 31, 2022, long-term debt consisted of the following (in millions): June 30, 2023 December 31, 2022 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ 160.0 $ — $ 160.0 $ 255.0 $ — $ 255.0 AR Facility due 2025 (2) 313.1 — 313.1 500.0 — 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 — 421.6 421.6 (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 1,000.0 (2.9) 997.1 700.0 — 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, including current maturities of long-term debt $ 4,782.3 $ (8.5) 4,773.8 $ 4,764.2 $ (5.8) 4,758.4 Debt issuance cost (3) (35.0) (34.9) Less: Current maturities of long-term debt (4) (97.9) — Long-term debt, net of unamortized issuance cost $ 4,640.9 $ 4,723.5 ____________________________ (1) The effective interest rate was 6.8% and 6.5% at June 30, 2023 and December 31, 2022, respectively. (2) The effective interest rate was 6.1% and 5.3% at June 30, 2023 and December 31, 2022, respectively. (3) Net of accumulated amortization of $18.0 million and $15.1 million at June 30, 2023 and December 31, 2022, respectively. (4) The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes as of June 30, 2023 are classified as “Current maturities of long-term debt” on the consolidated balance sheet as these notes mature on April 1, 2024. 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 $160.0 million in outstanding borrowings under the Revolving Credit Facility and $21.3 million in outstanding letters of credit as of June 30, 2023. At June 30, 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 $509.2 million as of June 30, 2023. As of June 30, 2023, the AR Facility had a borrowing base of $371.7 million and there were $313.1 million in outstanding borrowings under the AR Facility. At June 30, 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.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2023
Income Tax Disclosure [Abstract]
Income Taxes	(7) Income Taxes The components of our income tax benefit (expense) are as follows (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Current income tax expense $ (0.2) $ (0.5) $ (0.3) $ (0.7) Deferred income tax benefit (expense) (18.8) 1.8 (29.6) (1.2) Income tax benefit (expense) $ (19.0) $ 1.3 $ (29.9) $ (1.9) The following schedule reconciles income tax benefit (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 Six Months Ended 2023 2022 2023 2022 Expected income tax expense based on federal statutory rate $ (15.4) $ (17.8) $ (29.9) $ (25.9) State income tax expense, net of federal benefit (2.0) (2.5) (3.8) (3.6) Unit-based compensation (1) 0.1 — 6.6 (2.0) Change in valuation allowance — 21.0 — 28.1 Other (1.7) 0.6 (2.8) 1.5 Income tax benefit (expense) $ (19.0) $ 1.3 $ (29.9) $ (1.9) ____________________________ (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 June 30, 2023, we had $800.9 million of deferred tax assets and $873.7 million of deferred tax liabilities for net deferred tax liabilities of $72.8 million. As of December 31, 2022, we had $714.1 million of deferred tax assets and $756.8 million of deferred tax liabilities for net deferred tax liabilities of $42.7 million. 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. As of June 30, 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. Excise Tax on Common Unit Repurchases In August 2022, the Inflation Reduction Act of 2022 was signed into law, which, among other things, imposed a 1.0% excise tax on net common unit repurchases made after December 31, 2022. As a result, we accrued $0.7 million of excise tax in connection with the common unit repurchases we completed for each of the three and six months ended June 30, 2023, which was recorded as an adjustment to the cost basis of common units repurchased in “Members’ equity” and “Other current liabilities” on the consolidated balance sheet as of June 30, 2023.

Certain Provisions of the ENLK

Certain Provisions of the ENLK Partnership Agreement	6 Months Ended
	Jun. 30, 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 June 30, 2023 and December 31, 2022, there were 54,303,780 and 54,168,359 Series B Preferred Units issued and outstanding, respectively. Redemption 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 have resumed paying the PIK distribution. Distributions 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 six months ended June 30, 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 Second Quarter of 2023 135,759 $ 15.3 August 11, 2023 2022 Fourth Quarter of 2021 — $ 19.2 February 11, 2022 (1) First Quarter of 2022 — $ 17.5 May 13, 2022 (2) Second Quarter of 2022 — $ 17.3 August 12, 2022 ____________________________ (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. Series B Preferred Units Taxable Income 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”). As of June 30, 2023, due to the application of the Allocation Cap, 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 $6.26 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 As of June 30, 2023 and December 31, 2022, there were 376,500 and 381,000 Series C Preferred Units issued and outstanding, respectively. 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 Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period. A summary of the distribution activity relating to the Series C Preferred Units during the six months ended June 30, 2023 and 2022 is provided below: Declaration period (1) Distribution rate (2) Cash distribution (in millions) Date paid/payable 2023 December 15, 2022 – March 14, 2023 8.846 % $ 8.4 March 15, 2023 March 15, 2023 – June 14, 2023 9.051 % $ 8.7 June 15, 2023 June 15, 2023 – September 14, 2023 9.618 % $ 9.3 September 15, 2023 2022 December 15, 2021 – June 14, 2022 6.000 % $ 12.0 June 15, 2022 June 15, 2022 – December 14, 2022 6.000 % $ 12.0 December 15, 2022 ____________________________ (1) Distributions on the Series C Preferred Units accrued and were cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, 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. (2) The initial distribution rate for the Series C Preferred Units from the date of original issue through December 14, 2022 was 6.0% per year. Starting on December 15, 2022, distributions on the Series C Preferred Units 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%. Beginning with the interest period starting on September 15, 2023, distributions on the Series C Preferred Units will accumulate at a forward-looking term rate based on SOFR (“Term SOFR”), plus a Term SOFR spread adjustment of 0.26161%, plus a spread of 4.11%.

Members' Equity

Members' Equity	6 Months Ended
	Jun. 30, 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 Six Months Ended 2023 2022 2023 2022 Publicly held ENLC common units 3,230,504 2,921,370 5,437,809 5,015,212 ENLC common units held by GIP (1) 1,910,877 675,095 4,147,987 675,095 Total ENLC common units 5,141,381 3,596,465 9,585,796 5,690,307 Aggregate cost for publicly held ENLC common units $ 32.2 $ 27.7 $ 59.0 $ 44.7 Aggregate cost for ENLC common units held by GIP 23.2 6.0 47.8 6.0 Excise tax on common unit repurchases 0.7 — 0.7 — Total aggregate cost for ENLC common units $ 56.1 $ 33.7 $ 107.5 $ 50.7 Average price paid per publicly held ENLC common unit (2) $ 9.96 $ 9.49 $ 10.85 $ 8.92 Average price paid per ENLC common unit held by GIP (2)(3) $ 12.12 $ 8.92 $ 11.53 $ 8.92 ____________________________ (1) The units repurchased in each quarter represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the prior quarter. (2) The average price paid per common unit excludes excise tax on common unit repurchases. (3) The per unit price we paid to GIP in each quarter was the average per unit price paid by us for publicly held ENLC common units repurchased in the prior quarter, less broker commissions. Additionally, on July 31, 2023, we repurchased 2,763,581 ENLC common units held by GIP at an aggregate cost of $27.5 million, or an average of $9.94 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 June 30, 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. As of June 30, 2023, $27.5 million is classified as “Other current liabilities” on the consolidated balance sheets related to our obligation to repurchase our common units from GIP. 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 Six Months Ended 2023 2022 2023 2022 Distributed earnings allocated to: Common units (1) $ 57.8 $ 54.3 $ 116.4 $ 108.7 Unvested unit-based awards (1) 1.0 1.4 1.9 2.5 Total distributed earnings $ 58.8 $ 55.7 $ 118.3 $ 111.2 Undistributed loss allocated to: Common units $ (4.4) $ 29.0 $ (5.7) $ 9.1 Unvested unit-based awards (0.1) 0.6 (0.1) 0.2 Total undistributed loss $ (4.5) $ 29.6 $ (5.8) $ 9.3 Net income attributable to ENLC allocated to: Common units $ 53.4 $ 83.3 $ 110.7 $ 117.8 Unvested unit-based awards 0.9 2.0 1.8 2.7 Total net income attributable to ENLC $ 54.3 $ 85.3 $ 112.5 $ 120.5 Net income attributable to ENLC per unit: Basic $ 0.12 $ 0.18 $ 0.24 $ 0.25 Diluted $ 0.12 $ 0.17 $ 0.24 $ 0.25 ____________________________ (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 Six Months Ended 2023 2022 2023 2022 Basic weighted average units outstanding: Weighted average common units outstanding 462.7 482.0 465.8 483.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 462.7 482.0 465.8 483.0 Dilutive effect of unvested unit-based awards 4.0 7.0 4.1 6.7 Total weighted average diluted common units outstanding 466.7 489.0 469.9 489.7 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 six months ended June 30, 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 Second Quarter of 2023 $ 0.12500 August 11, 2023 2022 Fourth Quarter of 2021 $ 0.11250 February 11, 2022 First Quarter of 2022 $ 0.11250 May 13, 2022 Second Quarter of 2022 $ 0.11250 August 12, 2022

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2023
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(10) Investment in Unconsolidated Affiliates As of June 30, 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 Six Months Ended 2023 2022 2023 2022 GCF Contributions $ — $ 0.5 $ 6.2 $ 0.5 Distributions $ (2.0) $ — $ (2.0) $ — Equity in loss $ (1.7) $ (0.9) $ (2.8) $ (1.6) Cedar Cove JV Distributions $ (0.2) $ (0.2) $ (0.3) $ (0.4) Equity in loss $ (0.5) $ (0.3) $ (1.1) $ (0.7) Matterhorn JV Contributions $ — $ 26.1 $ 43.5 $ 26.1 Equity in loss $ (2.4) $ — $ (0.8) $ — Total Contributions $ — $ 26.6 $ 49.7 $ 26.6 Distributions $ (2.2) $ (0.2) $ (2.3) $ (0.4) Equity in loss $ (4.6) $ (1.2) $ (4.7) $ (2.3) The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2023 and December 31, 2022 (in millions): June 30, 2023 December 31, 2022 GCF $ 27.7 $ 26.3 Cedar Cove JV (1) (5.8) (4.4) Matterhorn JV 106.6 63.9 Total investment in unconsolidated affiliates $ 128.5 $ 85.8 ____________________________

Employee Incentive Plans

Employee Incentive Plans	6 Months Ended
	Jun. 30, 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 Six Months Ended 2023 2022 2023 2022 Cost of unit-based compensation charged to operating expense $ 0.7 $ 1.2 $ 1.6 $ 2.8 Cost of unit-based compensation charged to general and administrative expense 3.8 4.5 6.9 9.5 Total unit-based compensation expense $ 4.5 $ 5.7 $ 8.5 $ 12.3 Amount of related income tax benefit recognized in net income (1) $ 1.1 $ 1.3 $ 2.0 $ 2.9 ____________________________ (1) The amount of related income tax benefit recognized in net income excluded book-to-tax differences recorded upon the vesting of unit-based awards. For additional information, see “Note 7—Income Taxes.” 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 six months ended June 30, 2023 is provided below: Six Months Ended Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 6,775,186 $ 5.89 Granted 1,290,501 10.81 Vested (1) (2,240,049) 6.04 Forfeited (230,507) 6.17 Unvested, end of period 5,595,131 $ 6.95 Aggregate intrinsic value, end of period (in millions) $ 59.3 ____________________________ (1) Vested units included 668,083 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 and six months ended June 30, 2023 and 2022 is provided below (in millions): Three Months Ended Six Months Ended Restricted Incentive Units: 2023 2022 2023 2022 Aggregate intrinsic value of units vested $ 0.4 $ 0.6 $ 27.5 $ 8.2 Fair value of units vested $ 0.1 $ 0.5 $ 13.5 $ 11.2 As of June 30, 2023, there were $22.1 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 1.9 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: Six Months Ended 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) $ 26.5 ____________________________ (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 six months ended June 30, 2023 and 2022 is provided below (in millions). Six Months Ended 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 June 30, 2023, there were $12.5 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 1.8 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 %

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 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 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 Six Months Ended 2023 2022 2023 2022 Change in fair value of interest rate swaps $ 7.5 $ — $ 5.9 $ 0.1 Tax expense (1.8) — (1.4) — Unrealized gain on designated cash flow hedge $ 5.7 $ — $ 4.5 $ 0.1 The fair value of derivative assets and liabilities related to interest rate swaps are as follows (in millions): June 30, 2023 December 31, 2022 Fair value of derivative assets—current $ 5.5 $ — Fair value of derivative assets—long-term 0.4 — Net fair value of interest rate swaps $ 5.9 $ — Interest expense (income) is recognized from accumulated other comprehensive income from the monthly settlement of our interest rate swaps and was included in our consolidated statements of operations as follows (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Interest expense, net of interest income $ (1.1) $ — $ (1.6) $ 0.1 We expect to recognize an additional $5.5 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 Six Months Ended 2023 2022 2023 2022 Change in fair value of derivatives $ 5.3 $ 35.3 $ 3.9 $ 20.2 Realized gain (loss) on derivatives 6.0 (30.8) 19.3 (46.9) Gain (loss) on derivative activity $ 11.3 $ 4.5 $ 23.2 $ (26.7) The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): June 30, 2023 December 31, 2022 Fair value of derivative assets—current $ 78.3 $ 68.4 Fair value of derivative assets—long-term 17.9 2.9 Fair value of derivative liabilities—current (49.2) (42.9) Fair value of derivative liabilities—long-term (17.4) (2.7) Net fair value of commodity derivatives $ 29.6 $ 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 June 30, 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 (83.4) $ 23.8 NGL (long contracts) Swaps MMgals 72.7 (7.5) Natural gas (short contracts) Swaps and futures Bbtu (126.0) 32.5 Natural gas (long contracts) Swaps and futures Bbtu 109.6 (20.6) Crude and condensate (short contracts) Swaps and futures MMbbls (8.2) 5.9 Crude and condensate (long contracts) Swaps and futures MMbbls 0.7 (4.5) Total fair value of commodity derivatives $ 29.6 On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. 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 $96.2 million as of June 30, 2023 would be reduced to $30.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs and the FCDTCs.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2023
Fair Value Disclosures [Abstract]
Fair Value Measurements	(13) Fair Value Measurements Derivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2023 December 31, 2022 Interest rate swaps (1) $ 5.9 $ — Commodity derivatives (2) $ 29.6 $ 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): June 30, 2023 December 31, 2022 Carrying Value Fair Carrying Value Fair Long-term debt, including current maturities of long-term debt (1) $ 4,738.8 $ 4,485.2 $ 4,723.5 $ 4,385.9 Contingent consideration (2)(3) $ 6.4 $ 6.4 $ 5.5 $ 5.5 ____________________________ (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance cost, net of accumulated amortization, of $35.0 million and $34.9 million as of June 30, 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 June 30, 2023 and December 31, 2022 were based on Level 2 inputs from third-party market quotations.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 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 June 30, 2023 Natural gas sales $ 76.4 $ 92.5 $ 32.9 $ 16.7 $ — $ 218.5 NGL sales — 648.6 0.4 (1.9) — 647.1 Crude oil and condensate sales 294.4 52.6 26.7 — — 373.7 Product sales 370.8 793.7 60.0 14.8 — 1,239.3 NGL sales—related parties 204.1 5.3 102.3 66.2 (377.9) — Crude oil and condensate sales—related parties — — — 2.8 (2.8) — Product sales—related parties 204.1 5.3 102.3 69.0 (380.7) — Gathering and transportation 29.3 18.7 60.5 51.9 — 160.4 Processing 14.5 0.1 36.4 30.5 — 81.5 NGL services — 17.4 — 0.1 — 17.5 Crude services 7.0 5.6 4.9 0.2 — 17.7 Other services 1.6 0.3 0.2 0.3 — 2.4 Midstream services 52.4 42.1 102.0 83.0 — 279.5 NGL services—related parties — — — 0.8 (0.8) — Midstream services—related parties — — — 0.8 (0.8) — Revenue from contracts with customers 627.3 841.1 264.3 167.6 (381.5) 1,518.8 Realized gain (loss) on derivatives 5.4 (7.8) 1.9 6.5 — 6.0 Change in fair value of derivatives (7.9) 18.2 2.0 (7.0) — 5.3 Total revenues 624.8 851.5 268.2 167.1 (381.5) 1,530.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (479.9) (715.0) (130.5) (75.1) 381.5 (1,019.0) Adjusted gross margin 144.9 136.5 137.7 92.0 — 511.1 Operating expenses (53.1) (32.0) (27.0) (24.7) — (136.8) Segment profit 91.8 104.5 110.7 67.3 — 374.3 Depreciation and amortization (41.5) (36.9) (56.6) (29.0) (1.3) (165.3) Gross margin 50.3 67.6 54.1 38.3 (1.3) 209.0 Gain on disposition of assets 0.1 0.1 0.1 0.5 — 0.8 General and administrative — — — — (27.9) (27.9) Interest expense, net of interest income — — — — (68.8) (68.8) Loss from unconsolidated affiliate investments — — — — (4.6) (4.6) Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ 50.4 $ 67.7 $ 54.2 $ 38.8 $ (102.2) $ 108.9 Capital expenditures $ 51.6 $ 17.7 $ 22.1 $ 11.8 $ 1.5 $ 104.7 Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended June 30, 2022 Natural gas sales $ 323.0 $ 272.9 $ 87.1 $ 37.9 $ — $ 720.9 NGL sales — 1,163.7 3.6 0.1 — 1,167.4 Crude oil and condensate sales 331.6 110.0 40.6 — — 482.2 Product sales 654.6 1,546.6 131.3 38.0 — 2,370.5 NGL sales—related parties 427.5 43.1 242.6 165.8 (879.0) — Crude oil and condensate sales—related parties — — — 4.0 (4.0) — Product sales—related parties 427.5 43.1 242.6 169.8 (883.0) — Gathering and transportation 19.9 15.7 44.7 40.6 — 120.9 Processing 9.9 0.3 28.6 27.9 — 66.7 NGL services — 18.4 — 0.1 — 18.5 Crude services 6.0 9.2 3.2 0.2 — 18.6 Other services 0.2 0.4 0.1 0.2 — 0.9 Midstream services 36.0 44.0 76.6 69.0 — 225.6 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 1,118.1 1,633.7 450.6 276.8 (883.1) 2,596.1 Realized loss on derivatives (10.2) (2.5) (15.8) (2.3) — (30.8) Change in fair value of derivatives 12.5 11.8 8.2 2.8 — 35.3 Total revenues 1,120.4 1,643.0 443.0 277.3 (883.1) 2,600.6 Cost of sales, exclusive of operating expenses and depreciation and amortization (958.0) (1,519.2) (321.3) (189.7) 883.1 (2,105.1) Adjusted gross margin 162.4 123.8 121.7 87.6 — 495.5 Operating expenses (50.3) (34.8) (23.1) (20.7) — (128.9) Segment profit 112.1 89.0 98.6 66.9 — 366.6 Depreciation and amortization (37.1) (39.4) (52.3) (28.7) (1.5) (159.0) Gross margin 75.0 49.6 46.3 38.2 (1.5) 207.6 Gain on disposition of assets — — 0.2 0.2 — 0.4 General and administrative — — — — (28.4) (28.4) Interest expense, net of interest income — — — — (55.5) (55.5) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (1.2) (1.2) Other income — — — — 0.2 0.2 Income (loss) before non-controlling interest and income taxes $ 75.0 $ 49.6 $ 46.5 $ 38.4 $ (86.9) $ 122.6 Capital expenditures $ 34.7 $ 6.3 $ 11.5 $ 8.1 $ 1.9 $ 62.5 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2023 Natural gas sales $ 205.7 $ 224.3 $ 99.7 $ 31.2 $ — $ 560.9 NGL sales 0.4 1,506.5 9.0 (2.9) — 1,513.0 Crude oil and condensate sales 481.1 109.2 51.4 — — 641.7 Product sales 687.2 1,840.0 160.1 28.3 — 2,715.6 NGL sales—related parties 441.6 9.7 220.3 145.7 (817.3) — Crude oil and condensate sales—related parties — — — 5.5 (5.5) — Product sales—related parties 441.6 9.7 220.3 151.2 (822.8) — Gathering and transportation 52.6 38.7 115.3 104.0 — 310.6 Processing 28.5 0.4 71.7 62.6 — 163.2 NGL services — 45.2 — 0.1 — 45.3 Crude services 13.0 12.1 9.4 0.4 — 34.9 Other services 3.3 0.7 0.3 0.5 — 4.8 Midstream services 97.4 97.1 196.7 167.6 — 558.8 NGL services—related parties — — — 1.4 (1.4) — Midstream services—related parties — — — 1.4 (1.4) — Revenue from contracts with customers 1,226.2 1,946.8 577.1 348.5 (824.2) 3,274.4 Realized gain (loss) on derivatives 1.4 (0.6) 3.9 14.6 — 19.3 Change in fair value of derivatives (1.6) 9.2 0.6 (4.3) — 3.9 Total revenues 1,226.0 1,955.4 581.6 358.8 (824.2) 3,297.6 Cost of sales, exclusive of operating expenses and depreciation and amortization (937.0) (1,688.9) (324.5) (164.7) 824.2 (2,290.9) Adjusted gross margin 289.0 266.5 257.1 194.1 — 1,006.7 Operating expenses (101.2) (65.6) (51.7) (50.7) — (269.2) Segment profit 187.8 200.9 205.4 143.4 — 737.5 Depreciation and amortization (81.5) (75.2) (108.5) (57.8) (2.7) (325.7) Gross margin 106.3 125.7 96.9 85.6 (2.7) 411.8 Gain on disposition of assets 0.1 0.2 0.3 0.6 — 1.2 General and administrative — — — — (57.4) (57.4) Interest expense, net of interest income — — — — (137.3) (137.3) Loss from unconsolidated affiliate investments — — — — (4.7) (4.7) Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ 106.4 $ 125.9 $ 97.2 $ 86.2 $ (201.7) $ 214.0 Capital expenditures $ 108.3 $ 30.0 $ 47.8 $ 29.9 $ 2.8 $ 218.8 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2022 Natural gas sales $ 518.6 $ 484.4 $ 163.4 $ 63.3 $ — $ 1,229.7 NGL sales — 2,315.2 6.7 — — 2,321.9 Crude oil and condensate sales 603.6 183.9 75.3 — — 862.8 Product sales 1,122.2 2,983.5 245.4 63.3 — 4,414.4 NGL sales—related parties 827.3 80.0 450.7 312.7 (1,670.7) — Crude oil and condensate sales—related parties — — 0.3 7.0 (7.3) — Product sales—related parties 827.3 80.0 451.0 319.7 (1,678.0) — Gathering and transportation 33.5 32.0 87.4 79.4 — 232.3 Processing 17.7 0.8 54.0 55.5 — 128.0 NGL services — 42.3 — 0.1 — 42.4 Crude services 10.3 18.6 6.9 0.4 — 36.2 Other services 0.4 0.8 0.2 0.3 — 1.7 Midstream services 61.9 94.5 148.5 135.7 — 440.6 Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 0.1 — — (0.1) — Midstream services—related parties — 0.1 0.1 — (0.2) — Revenue from contracts with customers 2,011.4 3,158.1 845.0 518.7 (1,678.2) 4,855.0 Realized loss on derivatives (12.6) (9.1) (19.5) (5.7) — (46.9) Change in fair value of derivatives 6.6 6.2 1.1 6.3 — 20.2 Total revenues 2,005.4 3,155.2 826.6 519.3 (1,678.2) 4,828.3 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,724.7) (2,907.9) (598.1) (347.1) 1,678.2 (3,899.6) Adjusted gross margin 280.7 247.3 228.5 172.2 — 928.7 Operating expenses (95.6) (67.8) (44.1) (42.3) — (249.8) Segment profit 185.1 179.5 184.4 129.9 — 678.9 Depreciation and amortization (73.8) (74.9) (103.2) (57.1) (2.9) (311.9) Gross margin 111.3 104.6 81.2 72.8 (2.9) 367.0 Gain (loss) on disposition of assets — 0.2 0.4 (5.3) — (4.7) General and administrative — — — — (57.4) (57.4) Interest expense, net of interest income — — — — (110.6) (110.6) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (2.3) (2.3) Other income — — — — 0.3 0.3 Income (loss) before non-controlling interest and income taxes $ 111.3 $ 104.8 $ 81.6 $ 67.5 $ (173.4) $ 191.8 Capital expenditures $ 68.9 $ 12.0 $ 26.9 $ 11.2 $ 3.5 $ 122.5 The table below represents information about segment assets as of June 30, 2023 and December 31, 2022 (in millions): Segment Identifiable Assets: June 30, 2023 December 31, 2022 Permian $ 2,708.3 $ 2,661.4 Louisiana 2,077.6 2,310.7 Oklahoma 2,350.4 2,420.4 North Texas 1,038.9 1,094.6 Corporate (1) 224.7 163.9 Total identifiable assets $ 8,399.9 $ 8,651.0 ____________________________

Other Information

Other Information	6 Months Ended
	Jun. 30, 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: June 30, 2023 December 31, 2022 Natural gas and NGLs inventory $ 74.9 $ 147.1 Prepaid expenses and other 26.4 19.5 Other current assets $ 101.3 $ 166.6 Other current liabilities: June 30, 2023 December 31, 2022 Accrued interest $ 64.3 $ 57.6 Accrued wages and benefits, including taxes 15.3 38.1 Accrued ad valorem taxes 26.1 32.0 Accrued settlement of mandatorily redeemable non-controlling interest (1) — 10.5 Capital expenditure accruals 42.7 23.4 Short-term lease liability 26.6 26.2 Operating expense accruals 19.7 18.5 Other 44.1 23.3 Other current liabilities $ 238.8 $ 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.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 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. 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.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Pay vs Performance Disclosure
Net Income (Loss) Attributable to Parent	$ 54.3	$ 85.3	$ 112.5	$ 120.5

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended	6 Months Ended
	Jun. 30, 2023 shares	Jun. 30, 2023 shares
Trading Arrangements, by Individual
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false
Alaina K. Brooks [Member]
Trading Arrangements, by Individual
Material Terms of Trading Arrangement		On May 15, 2023, Alaina K. Brooks, Executive Vice President, Chief Legal and Administrative Officer, and Secretary of the Managing Member, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c) for the sale of up to 173,913 of our common units until May 14, 2024.
Name	Alaina K. Brooks
Title	Executive Vice President, Chief Legal and Administrative Officer, and Secretary of the Managing Member
Rule 10b5-1 Arrangement Adopted	true
Adoption Date	May 15, 2023
Arrangement Duration	365 days
Aggregate Available	173,913	173,913

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 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.

Significant Accounting Polices

Significant Accounting Polices (Tables)	6 Months Ended
	Jun. 30, 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) $ 76.6 2024 127.5 2025 110.4 2026 115.0 2027 98.1 Thereafter 1,120.1 Total $ 1,647.7

Acquisition (Tables)

Acquisition (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended June 30, 2023 2022 2023 2022 Amarillo Rattler Acquisition contingent consideration Contingent consideration liability, beginning of period (1) $ 4.7 $ 6.9 $ 4.2 $ 6.9 Change in fair value (0.1) 0.3 0.4 0.3 Contingent consideration liability, end of period $ 4.6 $ 7.2 $ 4.6 $ 7.2 Central Oklahoma Acquisition contingent consideration Contingent consideration liability, beginning of period (2) $ 1.5 $ — $ 1.3 $ — Change in fair value 0.3 — 0.5 — Contingent consideration liability, end of period $ 1.8 $ — $ 1.8 $ — Total contingent consideration Contingent consideration liability, beginning of period (1)(2) $ 6.2 $ 6.9 $ 5.5 $ 6.9 Change in fair value 0.2 0.3 0.9 0.3 Contingent consideration liability, end of period $ 6.4 $ 7.2 $ 6.4 $ 7.2 ____________________________ (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 and six months ended June 30, 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 Six Months Ended Pro forma total revenues $ 2,635.5 $ 4,892.4 Pro forma net income $ 139.2 $ 214.4

Intangible Assets (Tables)

Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended June 30, 2023 Customer relationships, beginning of period $ 1,844.8 $ (923.6) $ 921.2 Amortization expense — (63.8) (63.8) Customer relationships, end of period $ 1,844.8 $ (987.4) $ 857.4
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2023 (remaining) $ 63.8 2024 127.6 2025 110.2 2026 106.3 2027 106.3 Thereafter 343.2 Total $ 857.4

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2023
Debt Disclosure [Abstract]
Summary of Debt	As of June 30, 2023 and December 31, 2022, long-term debt consisted of the following (in millions): June 30, 2023 December 31, 2022 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ 160.0 $ — $ 160.0 $ 255.0 $ — $ 255.0 AR Facility due 2025 (2) 313.1 — 313.1 500.0 — 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 — 421.6 421.6 (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 1,000.0 (2.9) 997.1 700.0 — 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, including current maturities of long-term debt $ 4,782.3 $ (8.5) 4,773.8 $ 4,764.2 $ (5.8) 4,758.4 Debt issuance cost (3) (35.0) (34.9) Less: Current maturities of long-term debt (4) (97.9) — Long-term debt, net of unamortized issuance cost $ 4,640.9 $ 4,723.5 ____________________________ (1) The effective interest rate was 6.8% and 6.5% at June 30, 2023 and December 31, 2022, respectively. (2) The effective interest rate was 6.1% and 5.3% at June 30, 2023 and December 31, 2022, respectively. (3) Net of accumulated amortization of $18.0 million and $15.1 million at June 30, 2023 and December 31, 2022, respectively. (4) The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes as of June 30, 2023 are classified as “Current maturities of long-term debt” on the consolidated balance sheet as these notes mature on April 1, 2024.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2023
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax benefit (expense) are as follows (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Current income tax expense $ (0.2) $ (0.5) $ (0.3) $ (0.7) Deferred income tax benefit (expense) (18.8) 1.8 (29.6) (1.2) Income tax benefit (expense) $ (19.0) $ 1.3 $ (29.9) $ (1.9)
Reconciliation of Total Income Tax Expense to Income before Income Taxes	The following schedule reconciles income tax benefit (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 Six Months Ended 2023 2022 2023 2022 Expected income tax expense based on federal statutory rate $ (15.4) $ (17.8) $ (29.9) $ (25.9) State income tax expense, net of federal benefit (2.0) (2.5) (3.8) (3.6) Unit-based compensation (1) 0.1 — 6.6 (2.0) Change in valuation allowance — 21.0 — 28.1 Other (1.7) 0.6 (2.8) 1.5 Income tax benefit (expense) $ (19.0) $ 1.3 $ (29.9) $ (1.9) ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of unit-based awards.

Certain Provisions of the ENL_2

Certain Provisions of the ENLK Partnership Agreement (Tables)	6 Months Ended
	Jun. 30, 2023
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 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 Second Quarter of 2023 135,759 $ 15.3 August 11, 2023 2022 Fourth Quarter of 2021 — $ 19.2 February 11, 2022 (1) First Quarter of 2022 — $ 17.5 May 13, 2022 (2) Second Quarter of 2022 — $ 17.3 August 12, 2022 ____________________________ (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. Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period. A summary of the distribution activity relating to the Series C Preferred Units during the six months ended June 30, 2023 and 2022 is provided below: Declaration period (1) Distribution rate (2) Cash distribution (in millions) Date paid/payable 2023 December 15, 2022 – March 14, 2023 8.846 % $ 8.4 March 15, 2023 March 15, 2023 – June 14, 2023 9.051 % $ 8.7 June 15, 2023 June 15, 2023 – September 14, 2023 9.618 % $ 9.3 September 15, 2023 2022 December 15, 2021 – June 14, 2022 6.000 % $ 12.0 June 15, 2022 June 15, 2022 – December 14, 2022 6.000 % $ 12.0 December 15, 2022 ____________________________ (1) Distributions on the Series C Preferred Units accrued and were cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, 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. (2) The initial distribution rate for the Series C Preferred Units from the date of original issue through December 14, 2022 was 6.0% per year. Starting on December 15, 2022, distributions on the Series C Preferred Units 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%. Beginning with the interest period starting on September 15, 2023, distributions on the Series C Preferred Units will accumulate at a forward-looking term rate based on SOFR (“Term SOFR”), plus a Term SOFR spread adjustment of 0.26161%, plus a spread of 4.11%.

Members' Equity (Tables)

Members' Equity (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended 2023 2022 2023 2022 Publicly held ENLC common units 3,230,504 2,921,370 5,437,809 5,015,212 ENLC common units held by GIP (1) 1,910,877 675,095 4,147,987 675,095 Total ENLC common units 5,141,381 3,596,465 9,585,796 5,690,307 Aggregate cost for publicly held ENLC common units $ 32.2 $ 27.7 $ 59.0 $ 44.7 Aggregate cost for ENLC common units held by GIP 23.2 6.0 47.8 6.0 Excise tax on common unit repurchases 0.7 — 0.7 — Total aggregate cost for ENLC common units $ 56.1 $ 33.7 $ 107.5 $ 50.7 Average price paid per publicly held ENLC common unit (2) $ 9.96 $ 9.49 $ 10.85 $ 8.92 Average price paid per ENLC common unit held by GIP (2)(3) $ 12.12 $ 8.92 $ 11.53 $ 8.92 ____________________________ (1) The units repurchased in each quarter represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the prior quarter. (2) The average price paid per common unit excludes excise tax on common unit repurchases. (3) The per unit price we paid to GIP in each quarter was the average per unit price paid by us for publicly held ENLC common units repurchased in the prior quarter, less broker commissions.
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 Six Months Ended 2023 2022 2023 2022 Distributed earnings allocated to: Common units (1) $ 57.8 $ 54.3 $ 116.4 $ 108.7 Unvested unit-based awards (1) 1.0 1.4 1.9 2.5 Total distributed earnings $ 58.8 $ 55.7 $ 118.3 $ 111.2 Undistributed loss allocated to: Common units $ (4.4) $ 29.0 $ (5.7) $ 9.1 Unvested unit-based awards (0.1) 0.6 (0.1) 0.2 Total undistributed loss $ (4.5) $ 29.6 $ (5.8) $ 9.3 Net income attributable to ENLC allocated to: Common units $ 53.4 $ 83.3 $ 110.7 $ 117.8 Unvested unit-based awards 0.9 2.0 1.8 2.7 Total net income attributable to ENLC $ 54.3 $ 85.3 $ 112.5 $ 120.5 Net income attributable to ENLC per unit: Basic $ 0.12 $ 0.18 $ 0.24 $ 0.25 Diluted $ 0.12 $ 0.17 $ 0.24 $ 0.25 ____________________________ (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 Six Months Ended 2023 2022 2023 2022 Basic weighted average units outstanding: Weighted average common units outstanding 462.7 482.0 465.8 483.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 462.7 482.0 465.8 483.0 Dilutive effect of unvested unit-based awards 4.0 7.0 4.1 6.7 Total weighted average diluted common units outstanding 466.7 489.0 469.9 489.7
Summary of Distribution Activity	A summary of our distribution activity related to the ENLC common units for the six months ended June 30, 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 Second Quarter of 2023 $ 0.12500 August 11, 2023 2022 Fourth Quarter of 2021 $ 0.11250 February 11, 2022 First Quarter of 2022 $ 0.11250 May 13, 2022 Second Quarter of 2022 $ 0.11250 August 12, 2022

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended 2023 2022 2023 2022 GCF Contributions $ — $ 0.5 $ 6.2 $ 0.5 Distributions $ (2.0) $ — $ (2.0) $ — Equity in loss $ (1.7) $ (0.9) $ (2.8) $ (1.6) Cedar Cove JV Distributions $ (0.2) $ (0.2) $ (0.3) $ (0.4) Equity in loss $ (0.5) $ (0.3) $ (1.1) $ (0.7) Matterhorn JV Contributions $ — $ 26.1 $ 43.5 $ 26.1 Equity in loss $ (2.4) $ — $ (0.8) $ — Total Contributions $ — $ 26.6 $ 49.7 $ 26.6 Distributions $ (2.2) $ (0.2) $ (2.3) $ (0.4) Equity in loss $ (4.6) $ (1.2) $ (4.7) $ (2.3) The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2023 and December 31, 2022 (in millions): June 30, 2023 December 31, 2022 GCF $ 27.7 $ 26.3 Cedar Cove JV (1) (5.8) (4.4) Matterhorn JV 106.6 63.9 Total investment in unconsolidated affiliates $ 128.5 $ 85.8 ____________________________

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	6 Months Ended
	Jun. 30, 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 Six Months Ended 2023 2022 2023 2022 Cost of unit-based compensation charged to operating expense $ 0.7 $ 1.2 $ 1.6 $ 2.8 Cost of unit-based compensation charged to general and administrative expense 3.8 4.5 6.9 9.5 Total unit-based compensation expense $ 4.5 $ 5.7 $ 8.5 $ 12.3 Amount of related income tax benefit recognized in net income (1) $ 1.1 $ 1.3 $ 2.0 $ 2.9 ____________________________ (1) The amount of related income tax benefit recognized in net income excluded book-to-tax differences recorded upon the vesting of unit-based awards. For additional information, see “Note 7—Income Taxes.”
Schedule Of Restricted Stock Units Activity, ENLC	A summary of the restricted incentive unit activity for the six months ended June 30, 2023 is provided below: Six Months Ended Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 6,775,186 $ 5.89 Granted 1,290,501 10.81 Vested (1) (2,240,049) 6.04 Forfeited (230,507) 6.17 Unvested, end of period 5,595,131 $ 6.95 Aggregate intrinsic value, end of period (in millions) $ 59.3
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units, Vested and Fair Value Vested, ENLC	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2023 and 2022 is provided below (in millions): Three Months Ended Six Months Ended Restricted Incentive Units: 2023 2022 2023 2022 Aggregate intrinsic value of units vested $ 0.4 $ 0.6 $ 27.5 $ 8.2 Fair value of units vested $ 0.1 $ 0.5 $ 13.5 $ 11.2
Summary of Performance Units, ENLC	The following table presents a summary of the performance units: Six Months Ended 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) $ 26.5 ____________________________ (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 six months ended June 30, 2023 and 2022 is provided below (in millions). Six Months Ended 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 %

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Change in fair value of interest rate swaps $ 7.5 $ — $ 5.9 $ 0.1 Tax expense (1.8) — (1.4) — Unrealized gain on designated cash flow hedge $ 5.7 $ — $ 4.5 $ 0.1 Interest expense (income) is recognized from accumulated other comprehensive income from the monthly settlement of our interest rate swaps and was included in our consolidated statements of operations as follows (in millions): Three Months Ended Six Months Ended 2023 2022 2023 2022 Interest expense, net of interest income $ (1.1) $ — $ (1.6) $ 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 Six Months Ended 2023 2022 2023 2022 Change in fair value of derivatives $ 5.3 $ 35.3 $ 3.9 $ 20.2 Realized gain (loss) on derivatives 6.0 (30.8) 19.3 (46.9) Gain (loss) on derivative activity $ 11.3 $ 4.5 $ 23.2 $ (26.7)
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): June 30, 2023 December 31, 2022 Fair value of derivative assets—current $ 5.5 $ — Fair value of derivative assets—long-term 0.4 — Net fair value of interest rate swaps $ 5.9 $ — The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): June 30, 2023 December 31, 2022 Fair value of derivative assets—current $ 78.3 $ 68.4 Fair value of derivative assets—long-term 17.9 2.9 Fair value of derivative liabilities—current (49.2) (42.9) Fair value of derivative liabilities—long-term (17.4) (2.7) Net fair value of commodity derivatives $ 29.6 $ 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 June 30, 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 (83.4) $ 23.8 NGL (long contracts) Swaps MMgals 72.7 (7.5) Natural gas (short contracts) Swaps and futures Bbtu (126.0) 32.5 Natural gas (long contracts) Swaps and futures Bbtu 109.6 (20.6) Crude and condensate (short contracts) Swaps and futures MMbbls (8.2) 5.9 Crude and condensate (long contracts) Swaps and futures MMbbls 0.7 (4.5) Total fair value of commodity derivatives $ 29.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2023
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Derivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2023 December 31, 2022 Interest rate swaps (1) $ 5.9 $ — Commodity derivatives (2) $ 29.6 $ 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): June 30, 2023 December 31, 2022 Carrying Value Fair Carrying Value Fair Long-term debt, including current maturities of long-term debt (1) $ 4,738.8 $ 4,485.2 $ 4,723.5 $ 4,385.9 Contingent consideration (2)(3) $ 6.4 $ 6.4 $ 5.5 $ 5.5 ____________________________ (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance cost, net of accumulated amortization, of $35.0 million and $34.9 million as of June 30, 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.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2023 Natural gas sales $ 76.4 $ 92.5 $ 32.9 $ 16.7 $ — $ 218.5 NGL sales — 648.6 0.4 (1.9) — 647.1 Crude oil and condensate sales 294.4 52.6 26.7 — — 373.7 Product sales 370.8 793.7 60.0 14.8 — 1,239.3 NGL sales—related parties 204.1 5.3 102.3 66.2 (377.9) — Crude oil and condensate sales—related parties — — — 2.8 (2.8) — Product sales—related parties 204.1 5.3 102.3 69.0 (380.7) — Gathering and transportation 29.3 18.7 60.5 51.9 — 160.4 Processing 14.5 0.1 36.4 30.5 — 81.5 NGL services — 17.4 — 0.1 — 17.5 Crude services 7.0 5.6 4.9 0.2 — 17.7 Other services 1.6 0.3 0.2 0.3 — 2.4 Midstream services 52.4 42.1 102.0 83.0 — 279.5 NGL services—related parties — — — 0.8 (0.8) — Midstream services—related parties — — — 0.8 (0.8) — Revenue from contracts with customers 627.3 841.1 264.3 167.6 (381.5) 1,518.8 Realized gain (loss) on derivatives 5.4 (7.8) 1.9 6.5 — 6.0 Change in fair value of derivatives (7.9) 18.2 2.0 (7.0) — 5.3 Total revenues 624.8 851.5 268.2 167.1 (381.5) 1,530.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (479.9) (715.0) (130.5) (75.1) 381.5 (1,019.0) Adjusted gross margin 144.9 136.5 137.7 92.0 — 511.1 Operating expenses (53.1) (32.0) (27.0) (24.7) — (136.8) Segment profit 91.8 104.5 110.7 67.3 — 374.3 Depreciation and amortization (41.5) (36.9) (56.6) (29.0) (1.3) (165.3) Gross margin 50.3 67.6 54.1 38.3 (1.3) 209.0 Gain on disposition of assets 0.1 0.1 0.1 0.5 — 0.8 General and administrative — — — — (27.9) (27.9) Interest expense, net of interest income — — — — (68.8) (68.8) Loss from unconsolidated affiliate investments — — — — (4.6) (4.6) Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ 50.4 $ 67.7 $ 54.2 $ 38.8 $ (102.2) $ 108.9 Capital expenditures $ 51.6 $ 17.7 $ 22.1 $ 11.8 $ 1.5 $ 104.7 Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended June 30, 2022 Natural gas sales $ 323.0 $ 272.9 $ 87.1 $ 37.9 $ — $ 720.9 NGL sales — 1,163.7 3.6 0.1 — 1,167.4 Crude oil and condensate sales 331.6 110.0 40.6 — — 482.2 Product sales 654.6 1,546.6 131.3 38.0 — 2,370.5 NGL sales—related parties 427.5 43.1 242.6 165.8 (879.0) — Crude oil and condensate sales—related parties — — — 4.0 (4.0) — Product sales—related parties 427.5 43.1 242.6 169.8 (883.0) — Gathering and transportation 19.9 15.7 44.7 40.6 — 120.9 Processing 9.9 0.3 28.6 27.9 — 66.7 NGL services — 18.4 — 0.1 — 18.5 Crude services 6.0 9.2 3.2 0.2 — 18.6 Other services 0.2 0.4 0.1 0.2 — 0.9 Midstream services 36.0 44.0 76.6 69.0 — 225.6 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 1,118.1 1,633.7 450.6 276.8 (883.1) 2,596.1 Realized loss on derivatives (10.2) (2.5) (15.8) (2.3) — (30.8) Change in fair value of derivatives 12.5 11.8 8.2 2.8 — 35.3 Total revenues 1,120.4 1,643.0 443.0 277.3 (883.1) 2,600.6 Cost of sales, exclusive of operating expenses and depreciation and amortization (958.0) (1,519.2) (321.3) (189.7) 883.1 (2,105.1) Adjusted gross margin 162.4 123.8 121.7 87.6 — 495.5 Operating expenses (50.3) (34.8) (23.1) (20.7) — (128.9) Segment profit 112.1 89.0 98.6 66.9 — 366.6 Depreciation and amortization (37.1) (39.4) (52.3) (28.7) (1.5) (159.0) Gross margin 75.0 49.6 46.3 38.2 (1.5) 207.6 Gain on disposition of assets — — 0.2 0.2 — 0.4 General and administrative — — — — (28.4) (28.4) Interest expense, net of interest income — — — — (55.5) (55.5) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (1.2) (1.2) Other income — — — — 0.2 0.2 Income (loss) before non-controlling interest and income taxes $ 75.0 $ 49.6 $ 46.5 $ 38.4 $ (86.9) $ 122.6 Capital expenditures $ 34.7 $ 6.3 $ 11.5 $ 8.1 $ 1.9 $ 62.5 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2023 Natural gas sales $ 205.7 $ 224.3 $ 99.7 $ 31.2 $ — $ 560.9 NGL sales 0.4 1,506.5 9.0 (2.9) — 1,513.0 Crude oil and condensate sales 481.1 109.2 51.4 — — 641.7 Product sales 687.2 1,840.0 160.1 28.3 — 2,715.6 NGL sales—related parties 441.6 9.7 220.3 145.7 (817.3) — Crude oil and condensate sales—related parties — — — 5.5 (5.5) — Product sales—related parties 441.6 9.7 220.3 151.2 (822.8) — Gathering and transportation 52.6 38.7 115.3 104.0 — 310.6 Processing 28.5 0.4 71.7 62.6 — 163.2 NGL services — 45.2 — 0.1 — 45.3 Crude services 13.0 12.1 9.4 0.4 — 34.9 Other services 3.3 0.7 0.3 0.5 — 4.8 Midstream services 97.4 97.1 196.7 167.6 — 558.8 NGL services—related parties — — — 1.4 (1.4) — Midstream services—related parties — — — 1.4 (1.4) — Revenue from contracts with customers 1,226.2 1,946.8 577.1 348.5 (824.2) 3,274.4 Realized gain (loss) on derivatives 1.4 (0.6) 3.9 14.6 — 19.3 Change in fair value of derivatives (1.6) 9.2 0.6 (4.3) — 3.9 Total revenues 1,226.0 1,955.4 581.6 358.8 (824.2) 3,297.6 Cost of sales, exclusive of operating expenses and depreciation and amortization (937.0) (1,688.9) (324.5) (164.7) 824.2 (2,290.9) Adjusted gross margin 289.0 266.5 257.1 194.1 — 1,006.7 Operating expenses (101.2) (65.6) (51.7) (50.7) — (269.2) Segment profit 187.8 200.9 205.4 143.4 — 737.5 Depreciation and amortization (81.5) (75.2) (108.5) (57.8) (2.7) (325.7) Gross margin 106.3 125.7 96.9 85.6 (2.7) 411.8 Gain on disposition of assets 0.1 0.2 0.3 0.6 — 1.2 General and administrative — — — — (57.4) (57.4) Interest expense, net of interest income — — — — (137.3) (137.3) Loss from unconsolidated affiliate investments — — — — (4.7) (4.7) Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ 106.4 $ 125.9 $ 97.2 $ 86.2 $ (201.7) $ 214.0 Capital expenditures $ 108.3 $ 30.0 $ 47.8 $ 29.9 $ 2.8 $ 218.8 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2022 Natural gas sales $ 518.6 $ 484.4 $ 163.4 $ 63.3 $ — $ 1,229.7 NGL sales — 2,315.2 6.7 — — 2,321.9 Crude oil and condensate sales 603.6 183.9 75.3 — — 862.8 Product sales 1,122.2 2,983.5 245.4 63.3 — 4,414.4 NGL sales—related parties 827.3 80.0 450.7 312.7 (1,670.7) — Crude oil and condensate sales—related parties — — 0.3 7.0 (7.3) — Product sales—related parties 827.3 80.0 451.0 319.7 (1,678.0) — Gathering and transportation 33.5 32.0 87.4 79.4 — 232.3 Processing 17.7 0.8 54.0 55.5 — 128.0 NGL services — 42.3 — 0.1 — 42.4 Crude services 10.3 18.6 6.9 0.4 — 36.2 Other services 0.4 0.8 0.2 0.3 — 1.7 Midstream services 61.9 94.5 148.5 135.7 — 440.6 Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 0.1 — — (0.1) — Midstream services—related parties — 0.1 0.1 — (0.2) — Revenue from contracts with customers 2,011.4 3,158.1 845.0 518.7 (1,678.2) 4,855.0 Realized loss on derivatives (12.6) (9.1) (19.5) (5.7) — (46.9) Change in fair value of derivatives 6.6 6.2 1.1 6.3 — 20.2 Total revenues 2,005.4 3,155.2 826.6 519.3 (1,678.2) 4,828.3 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,724.7) (2,907.9) (598.1) (347.1) 1,678.2 (3,899.6) Adjusted gross margin 280.7 247.3 228.5 172.2 — 928.7 Operating expenses (95.6) (67.8) (44.1) (42.3) — (249.8) Segment profit 185.1 179.5 184.4 129.9 — 678.9 Depreciation and amortization (73.8) (74.9) (103.2) (57.1) (2.9) (311.9) Gross margin 111.3 104.6 81.2 72.8 (2.9) 367.0 Gain (loss) on disposition of assets — 0.2 0.4 (5.3) — (4.7) General and administrative — — — — (57.4) (57.4) Interest expense, net of interest income — — — — (110.6) (110.6) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (2.3) (2.3) Other income — — — — 0.3 0.3 Income (loss) before non-controlling interest and income taxes $ 111.3 $ 104.8 $ 81.6 $ 67.5 $ (173.4) $ 191.8 Capital expenditures $ 68.9 $ 12.0 $ 26.9 $ 11.2 $ 3.5 $ 122.5
Schedule of Segment Assets	The table below represents information about segment assets as of June 30, 2023 and December 31, 2022 (in millions): Segment Identifiable Assets: June 30, 2023 December 31, 2022 Permian $ 2,708.3 $ 2,661.4 Louisiana 2,077.6 2,310.7 Oklahoma 2,350.4 2,420.4 North Texas 1,038.9 1,094.6 Corporate (1) 224.7 163.9 Total identifiable assets $ 8,399.9 $ 8,651.0 ____________________________

Other Information (Tables)

Other Information (Tables)	6 Months Ended
	Jun. 30, 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: June 30, 2023 December 31, 2022 Natural gas and NGLs inventory $ 74.9 $ 147.1 Prepaid expenses and other 26.4 19.5 Other current assets $ 101.3 $ 166.6 Other current liabilities: June 30, 2023 December 31, 2022 Accrued interest $ 64.3 $ 57.6 Accrued wages and benefits, including taxes 15.3 38.1 Accrued ad valorem taxes 26.1 32.0 Accrued settlement of mandatorily redeemable non-controlling interest (1) — 10.5 Capital expenditure accruals 42.7 23.4 Short-term lease liability 26.6 26.2 Operating expense accruals 19.7 18.5 Other 44.1 23.3 Other current liabilities $ 238.8 $ 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.

General (Details)

General (Details)	6 Months Ended
	Jun. 30, 2023 Bcf / d fractionator processingPlant 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
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%

Significant Accounting Polici_3

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Jun. 30, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,647.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	6 months
Remaining performance obligations	$ 76.6
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	$ 127.5
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	$ 110.4
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	$ 115
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	$ 98.1
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	$ 1,120.1

Significant Accounting Polici_4

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

Acquisition - Narrative (Detail

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

Acquisition - Fair Value Of Ass

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
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

Acquisitions - Contingent Consi

Acquisitions - Contingent Consideration (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Business Combination, Contingent Consideration, Liability [Roll Forward]
Contingent consideration liability, beginning of period	$ 6.2	$ 6.9	$ 5.5	$ 6.9
Change in fair value	0.2	0.3	0.9	0.3
Contingent consideration liability, end of period	6.4	7.2	6.4	7.2
Amarillo Rattler, LLC
Business Combination, Contingent Consideration, Liability [Roll Forward]
Contingent consideration liability, beginning of period	4.7	6.9	4.2	6.9
Change in fair value	(0.1)	0.3	0.4	0.3
Contingent consideration liability, end of period	4.6	7.2	4.6	7.2
Central Oklahoma Acquisition
Business Combination, Contingent Consideration, Liability [Roll Forward]
Contingent consideration liability, beginning of period	1.5	0	1.3	0
Change in fair value	0.3	0	0.5	0
Contingent consideration liability, end of period	$ 1.8	$ 0	$ 1.8	$ 0

Acquisition - Pro Forma (Detail

Acquisition - Pro Forma (Details) - Crestwood Gas Services Operating LLC - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2022
Business Acquisition [Line Items]
Pro forma total revenues	$ 2,635.5	$ 4,892.4
Pro forma net income	$ 139.2	$ 214.4

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 31.9	$ 31.9	$ 63.8	$ 64.7
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	10 years		10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	20 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		14 years 10 months 24 days

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 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)	$ (31.9)	(63.8)	$ (64.7)
Gross carrying amount, ending balance	1,844.8		1,844.8
Accumulated amortization, ending balance	(987.4)		(987.4)
Net carrying amount, ending balance	$ 857.4		$ 857.4

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
2023	$ 63.8
2024	127.6
2025	110.2
2026	106.3
2027	106.3
Thereafter	343.2
Total	$ 857.4	$ 921.2

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022
Related Party Transaction [Line Items]
Revenue from contracts with customers		$ 1,518.8	$ 2,596.1	$ 3,274.4	$ 4,855
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	1,019	2,105.1	2,290.9	3,899.6
Accounts payable, current		101.2		101.2		$ 126.9
Midstream service
Related Party Transaction [Line Items]
Revenue from contracts with customers	[2]	279.5	225.6	558.8	440.6
Product sales—related parties
Related Party Transaction [Line Items]
Revenue from contracts with customers		0.6	0	1.3	0
Cost of sales, exclusive of operating expenses and depreciation and amortization		2.5	9.1	4	19.7
Accounts payable, current		0.3		0.3		2.5
Product sales—related parties | Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization		2.5	9.1	4	19.7
Accounts payable, current		0.3		0.3		$ 2.5
Product sales—related parties | GIP
Related Party Transaction [Line Items]
Selling, general and administrative expense		0	0	0	0
Product sales—related parties | Midstream service | Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Revenue from contracts with customers		$ 0.6	$ 0	$ 1.3	$ 0
[1]Includes related party cost of sales of $2.5 million and $9.1 million for the three months ended June 30, 2023 and 2022, respectively, and $4.0 million and $19.7 million for the six months ended June 30, 2023 and 2022, respectively.[2]Includes related party revenue of $0.6 million and $1.3 million for the three and six months ended June 30, 2023, respectively. We did not have related party revenue for the three and six months ended June 30, 2022.

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Debt Instrument
Outstanding Principal	$ 4,782.3	$ 4,764.2
Premium (Discount)	(8.5)	(5.8)
Long-Term Debt	4,773.8	4,758.4
Debt issuance costs	(35)	(34.9)
Less: Current maturities of long-term debt	(97.9)	0
Long-term debt, net of unamortized issuance cost	4,640.9	4,723.5
Debt issuance cost accumulated amortization	18	15.1
Revolving Credit Facility Due 2027
Debt Instrument
Outstanding Principal	160	255
Premium (Discount)	0	0
Long-Term Debt	$ 160	$ 255
Effective interest rate (as a percent)	6.80%	6.50%
AR Facility due 2025
Debt Instrument
Outstanding Principal	$ 313.1	$ 500
Premium (Discount)	0	0
Long-Term Debt	$ 313.1	$ 500
Effective interest rate (as a percent)	6.10%	5.30%
4.40% Senior Notes due 2024
Debt Instrument
Outstanding Principal	$ 97.9	$ 97.9
Premium (Discount)	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	(0.1)
Long-Term Debt	$ 421.6	421.5
Stated interest rate (as a percent)	4.15%
4.85% Senior Unsecured Notes Due 2026
Debt Instrument
Outstanding Principal	$ 491	491
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	500
Premium (Discount)	0	0
Long-Term Debt	$ 500	500
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
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	$ 1,000	700
Premium (Discount)	(2.9)	0
Long-Term Debt	$ 997.1	700
Stated interest rate (as a percent)	6.50%
5.60% Senior Notes due 2044
Debt Instrument
Outstanding Principal	$ 350	350
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	450
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	500
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9
Stated interest rate (as a percent)	5.45%

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($)		6 Months Ended
	Aug. 31, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022
Debt Instrument
Increase (decrease) in accounts receivable		$ 509,200,000
Outstanding Principal		4,782,300,000		$ 4,764,200,000
Proceeds from borrowings		2,004,100,000	$ 1,135,000,000
Unsecured Debt
Debt Instrument
Debt repurchased	$ 700,000,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity		371,700,000
Accounts receivable securitization facility, outstanding amount		313,100,000
Letters of credit
Debt Instrument
Additional amount available (not to exceed)		1,400,000,000
Line of credit facility, fair value of amount outstanding		160,000,000
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		21,300,000
6.50% Senior Notes due 2030
Debt Instrument
Outstanding Principal		$ 1,000,000,000		700,000,000
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%
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

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.2)	$ (0.5)	$ (0.3)	$ (0.7)
Deferred income tax benefit (expense)	(18.8)	1.8	(29.6)	(1.2)
Income tax benefit (expense)	(19)	1.3	(29.9)	(1.9)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax expense based on federal statutory rate	(15.4)	(17.8)	(29.9)	(25.9)
State income tax expense, net of federal benefit	(2)	(2.5)	(3.8)	(3.6)
Unit-based compensation	0.1	0	6.6	(2)
Change in valuation allowance	0	21	0	28.1
Other	(1.7)	0.6	(2.8)	1.5
Income tax benefit (expense)	$ (19)	$ 1.3	$ (29.9)	$ (1.9)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 800.9	$ 714.1
Deferred tax liabilities	(873.7)	(756.8)
Net deferred tax liabilities	(72.8)	$ (42.7)
Accrued excise taxes	$ 0.7

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions					1 Months Ended			3 Months Ended								6 Months Ended			15 Months Ended
	Sep. 15, 2023	Dec. 15, 2022	May 13, 2022	Feb. 11, 2022	Feb. 28, 2023	Jan. 31, 2022	Dec. 31, 2021	Jun. 30, 2023	Jun. 14, 2023	Mar. 31, 2023	Mar. 14, 2023	Dec. 31, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Jun. 30, 2023	Dec. 14, 2022	Jun. 14, 2022	Sep. 14, 2023	Jan. 31, 2023
Partnership agreement
Derivative, fixed interest rate																				3.8565%
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%
Redemption of Series B Preferred Units | Limited Partner
Partnership agreement
Distribution paid-in kind (in shares)								135,759		135,421		0	0	0	0
Cash distributions								$ 15.3		$ 15.2		$ 17.3	$ 17.3	$ 17.5	$ 19.2
Redemption of Series B Preferred Units | Limited Partner | Distribution, Tranche One
Partnership agreement
Distributions preferred units				$ 17.3		$ 1	$ 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)								54,303,780								54,303,780
Preferred units, outstanding (in shares)												54,168,359
Price payable, overage (in dollars per unit)																$ 6.26
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%
Distribution rate per unit		6%							9.051%		8.846%						6%	6%
Cash distributions									$ 8.7		$ 8.4						$ 12	$ 12
Redemption price (per unit)		$ 1,000
Variable floating rate percentage		4.11%
Repurchase of Series C Preferred Units | Forecast
Partnership agreement
Distribution rate per unit	0.26161%																		9.618%
Cash distributions																			$ 9.3
Variable floating rate percentage	4.11%
Repurchase of Series C Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)								376,500				381,000				376,500
Preferred units, outstanding (in shares)								376,500				381,000				376,500

Members' Equity - Narrative (De

Members' Equity - Narrative (Details) - USD ($)		3 Months Ended				6 Months Ended
	Jul. 31, 2023	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2023	Jun. 30, 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)		5,141,381		3,596,465		9,585,796	5,690,307
Aggregate cost for common units		$ 56,100,000	$ 51,400,000	$ 33,700,000	$ 17,000,000	$ 107,500,000	$ 50,700,000
Accrued common unit repurchase		$ 27,500,000				$ 27,500,000
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	2,763,581
Aggregate cost for common units	$ 27,500,000
Average price of shares repurchased (in dollars per share)	$ 9.94

Members' Equity - IP Repurchase

Members' Equity - IP Repurchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2023	Jun. 30, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	5,141,381		3,596,465		9,585,796	5,690,307
Aggregate cost for common units	$ 56.1	$ 51.4	$ 33.7	$ 17	$ 107.5	$ 50.7
Excise tax on common unit repurchases	$ 0.7		$ 0		$ 0.7	$ 0
Public ENLC Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	3,230,504		2,921,370		5,437,809	5,015,212
Aggregate cost for common units	$ 32.2		$ 27.7		$ 59	$ 44.7
Average price of shares repurchased (in dollars per share)	$ 9.96		$ 9.49		$ 10.85	$ 8.92
ENCL Common Units Held by GIP
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	1,910,877		675,095		4,147,987	675,095
Aggregate cost for common units	$ 23.2		$ 6		$ 47.8	$ 6
Average price of shares repurchased (in dollars per share)	$ 12.12		$ 8.92		$ 11.53	$ 8.92

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Distributed earnings allocated to:
Total distributed earnings	$ 58.8	$ 55.7	$ 118.3	$ 111.2
Undistributed loss allocated to:
Total undistributed loss, basic	(4.5)	29.6	(5.8)	9.3
Total undistributed loss, diluted	(4.5)	29.6	(5.8)	9.3
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	54.3	85.3	112.5	120.5
Total net income attributable to ENLC, diluted	$ 54.3	$ 85.3	$ 112.5	$ 120.5
Net income attributable to ENLC per unit:
Basic (in dollars per share)	$ 0.12	$ 0.18	$ 0.24	$ 0.25
Diluted (in dollars per share)	$ 0.12	$ 0.17	$ 0.24	$ 0.25
Unvested unit-based awards
Distributed earnings allocated to:
Total distributed earnings	$ 1	$ 1.4	$ 1.9	$ 2.5
Undistributed loss allocated to:
Total undistributed loss, basic	(0.1)	0.6	(0.1)	0.2
Total undistributed loss, diluted	(0.1)	0.6	(0.1)	0.2
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	0.9	2	1.8	2.7
Total net income attributable to ENLC, diluted	0.9	2	1.8	2.7
Common units
Distributed earnings allocated to:
Total distributed earnings	57.8	54.3	116.4	108.7
Undistributed loss allocated to:
Total undistributed loss, basic	(4.4)	29	(5.7)	9.1
Total undistributed loss, diluted	(4.4)	29	(5.7)	9.1
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	53.4	83.3	110.7	117.8
Total net income attributable to ENLC, diluted	$ 53.4	$ 83.3	$ 110.7	$ 117.8

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in shares)	462.7	482	465.8	483
Dilutive effect of unvested restricted units (in shares)	4	7	4.1	6.7
Total weighted average diluted common units outstanding (in shares)	466.7	489	469.9	489.7

Members' Equity - Distributions

Members' Equity - Distributions (Details) - $ / shares	3 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Distribution declared/unit (in dollars per share)	$ 0.12500	$ 0.12500	$ 0.12500	$ 0.11250	$ 0.11250	$ 0.11250

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022	Dec. 31, 2022
Equity method investments
Contributions	$ 0	$ 26.6	$ 49.7	$ 26.6
Distributions	(2.2)	(0.2)	(2.3)	(0.4)
Equity in income (loss)	(4.6)	(1.2)	(4.7)	(2.3)
Total investment in unconsolidated affiliates	$ 134.3		$ 134.3		$ 90.2
GCF
Equity method investments
Ownership interest	38.75%		38.75%
Contributions	$ 0	0.5	$ 6.2	0.5
Distributions	(2)	0	(2)	0
Equity in income (loss)	$ (1.7)	(0.9)	$ (2.8)	(1.6)
Cedar Cove JV
Equity method investments
Ownership interest	30%		30%
Distributions	$ (0.2)	(0.2)	$ (0.3)	(0.4)
Equity in income (loss)	$ (0.5)	(0.3)	$ (1.1)	(0.7)
Matterhorn JV
Equity method investments
Ownership interest	15%		15%
Contributions	$ 0	26.1	$ 43.5	26.1
Equity in income (loss)	(2.4)	$ 0	(0.8)	$ 0
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	128.5		128.5		85.8
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	27.7		27.7		26.3
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	(5.8)		(5.8)		(4.4)
EnLink Midstream Partners, LP | Matterhorn JV
Equity method investments
Total investment in unconsolidated affiliates	$ 106.6		$ 106.6		$ 63.9

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Allocation
Total unit-based compensation expense	$ 4.5	$ 5.7	$ 8.5	$ 12.3
Amount of related income tax benefit recognized in net income	1.1	1.3	2	2.9
Cost of unit-based compensation charged to operating expense
Allocation
Total unit-based compensation expense	0.7	1.2	1.6	2.8
Cost of unit-based compensation charged to general and administrative expense
Allocation
Total unit-based compensation expense	$ 3.8	$ 4.5	$ 6.9	$ 9.5

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2023	Mar. 31, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Unvested unit-based awards
Number of Units
Non-vested, beginning of period (in shares)		6,775,186		6,775,186
Granted (in shares)				1,290,501
Vested (in shares)				(2,240,049)
Forfeited (in shares)				(230,507)
Non-vested, end of period (in shares)	5,595,131			5,595,131
Aggregate intrinsic value, end of period	$ 59.3			$ 59.3
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)		$ 5.89		$ 5.89
Granted (in dollars per share)				10.81
Vested (in dollars per share)				6.04
Forfeited (in dollars per share)				6.17
Non-vested, end of period (in dollars per share)	$ 6.95			$ 6.95
Units withheld for payroll taxes (in shares)				668,083
Aggregate intrinsic value of units vested	$ 0.4		$ 0.6	$ 27.5	$ 8.2
Fair value of units vested	0.1		$ 0.5	13.5	11.2
Unrecognized compensation cost related to non-vested restricted incentive units	$ 22.1			$ 22.1
Unrecognized compensation costs, weighted average period for recognition (in years)				1 year 10 months 24 days
Performance units
Number of Units
Non-vested, beginning of period (in shares)		2,979,154		2,979,154
Granted (in shares)				420,128
Vested (in shares)				(899,919)
Non-vested, end of period (in shares)	2,499,363			2,499,363
Aggregate intrinsic value, end of period	$ 26.5			$ 26.5
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)		$ 6.44		$ 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			$ 6.39
Units withheld for payroll taxes (in shares)				668,829
Aggregate intrinsic value of units vested				$ 22	5.6
Fair value of units vested				8.1	$ 11
Unrecognized compensation cost related to non-vested restricted incentive units	$ 12.5			$ 12.5
Unrecognized compensation costs, weighted average period for recognition (in years)				1 year 9 months 18 days
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%
Performance units | Minimum
Performance Units:
Percent of units vesting (as a percent)				0%
Performance units | Maximum
Performance Units:
Percent of units vesting (as a percent)				200%

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) - USD ($)	Jun. 30, 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	$ 5,500,000
Commodity swaps
Derivatives
Maximum loss if counterparties fail to perform	96,200,000
Possible reduction in maximum loss if counterparties fail to perform	$ 30,500,000

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions	3 Months Ended							6 Months Ended
	Jun. 30, 2023		Mar. 31, 2023		Jun. 30, 2022		Mar. 31, 2022	Jun. 30, 2023		Jun. 30, 2022		Dec. 31, 2022
Derivatives
Tax expense	$ (1.8)		$ 0.4					$ (1.4)
Unrealized gain on designated cash flow hedge	5.7	[1],[2]	$ (1.2)	[3]	$ 0	[1]	$ 0.1	4.5	[1]	$ 0.1	[1]
Fair value of derivative assets—current	83.8							83.8				$ 68.4
Fair value of derivative assets	18.3							18.3				2.9
Interest expense, net of interest income	(1.1)				0			(1.6)		0.1
Interest rate swaps
Derivatives
Change in fair value of interest rate swaps	7.5				0			5.9		0.1
Tax expense	(1.8)				0			(1.4)		0
Unrealized gain on designated cash flow hedge	5.7				0			4.5		0.1
Fair value of derivative assets—current	5.5							5.5				0
Fair value of derivative assets	0.4				$ 0			0.4		$ 0
Net fair value of commodity derivatives	$ 5.9							$ 5.9				$ 0
[1]Includes tax expense of $1.8 million and $1.4 million for the three and six months ended June 30, 2023, respectively.[2]Includes tax expense of $1.8 million for the three months ended June 30, 2023.[3]Includes tax benefit of $0.4 million for the three months ended March 31, 2023.

Derivatives - Components of Com

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Derivatives
Change in fair value of interest rate swaps	$ 5.3	$ 35.3	$ 3.9	$ 20.2
Gain (loss) on derivative activity	11.3	4.5	23.2	(26.7)
Commodity swaps
Derivatives
Change in fair value of interest rate swaps	5.3	35.3
Realized gain (loss) on derivatives	6	(30.8)
Gain (loss) on derivative activity	$ 11.3	$ 4.5
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of interest rate swaps			3.9	20.2
Realized gain (loss) on derivatives			19.3	(46.9)
Gain (loss) on derivative activity			$ 23.2	$ (26.7)

Derivatives - Fair Value of Com

Derivatives - Fair Value of Commodity Swap Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Derivatives
Fair value of derivative assets—current	$ 83.8	$ 68.4
Fair value of derivative assets—long-term	18.3	2.9
Fair value of derivative liabilities—current	(49.2)	(42.9)
Fair value of derivative liabilities—long-term	(17.4)	(2.7)
Commodity swaps
Derivatives
Fair value of derivative assets—current	78.3	68.4
Fair value of derivative assets—long-term	17.9	2.9
Fair value of derivative liabilities—current	(49.2)	(42.9)
Fair value of derivative liabilities—long-term	(17.4)	(2.7)
Net fair value of commodity derivatives	$ 29.6	$ 25.7

Derivatives - Commodity Swaps A

Derivatives - Commodity Swaps Additional Information (Details) - Commodity swaps gal in Millions, bbl in Millions, BTU in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2023 USD ($) BTU bbl gal	Dec. 31, 2022 USD ($)
Derivatives
Net fair value of commodity derivatives	$ 29.6	$ 25.7
NGL | Short
Derivatives
Notional amount (in MMgasl or MMBLS) | gal	83.4
Net fair value of commodity derivatives	$ 23.8
NGL | Long
Derivatives
Notional amount (in MMgasl or MMBLS) | gal	72.7
Net fair value of commodity derivatives	$ (7.5)
Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | BTU	126
Net fair value of commodity derivatives	$ 32.5
Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | BTU	109.6
Net fair value of commodity derivatives	$ (20.6)
Crude and Condensate | Short
Derivatives
Notional amount (in MMgasl or MMBLS) | bbl	8.2
Net fair value of commodity derivatives	$ 5.9
Crude and Condensate | Long
Derivatives
Notional amount (in MMgasl or MMBLS) | bbl	0.7
Net fair value of commodity derivatives	$ (4.5)

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Interest rate swaps
Fair Value
Net fair value of commodity derivatives	$ 5.9	$ 0
Commodity swaps
Fair Value
Net fair value of commodity derivatives	29.6	25.7
Level 2 | Interest rate swaps | Recurring
Fair Value
Net fair value of commodity derivatives	5.9	0
Level 2 | Commodity swaps | Recurring
Fair Value
Net fair value of commodity derivatives	$ 29.6	$ 25.7

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Jun. 30, 2022	Apr. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Fair Value
Contingent consideration	$ 6.4	$ 6.2	$ 5.5	$ 7.2		$ 6.9	$ 6.9
Debt issuance costs	35		34.9
Amarillo Rattler, LLC
Fair Value
Contingent consideration	4.6	$ 4.7	4.2	$ 7.2		$ 6.9	$ 6.9
Business combination, maximum earnout					$ 15
Carrying Value
Fair Value
Long-term debt	4,738.8		4,723.5
Contingent consideration	6.4		5.5
Fair Value
Fair Value
Long-term debt	4,485.2		4,385.9
Contingent consideration	$ 6.4		$ 5.5

Segment Information - Narrative

Segment Information - Narrative (Details)	6 Months Ended
	Jun. 30, 2023 segment
Segment Reporting [Abstract]
Number of reportable segments	5

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2023	Jun. 30, 2022	Jun. 30, 2023	Jun. 30, 2022
Segment Reporting
Revenue from contracts with customers		$ 1,518.8	$ 2,596.1	$ 3,274.4	$ 4,855
Realized gain (loss) on derivatives		6	(30.8)	19.3	(46.9)
Change in fair value of interest rate swaps		5.3	35.3	3.9	20.2
Total revenues		1,530.1	2,600.6	3,297.6	4,828.3
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	(1,019)	(2,105.1)	(2,290.9)	(3,899.6)
Adjusted gross margin		511.1	495.5	1,006.7	928.7
Operating expenses		(136.8)	(128.9)	(269.2)	(249.8)
Segment profit		374.3	366.6	737.5	678.9
Depreciation and amortization		(165.3)	(159)	(325.7)	(311.9)
Gross margin		209	207.6	411.8	367
Gain on disposition of assets		0.8	0.4	1.2	(4.7)
General and administrative		(27.9)	(28.4)	(57.4)	(57.4)
Interest expense, net of interest income		(68.8)	(55.5)	(137.3)	(110.6)
Gain on extinguishment of debt		0	(0.5)	0	(0.5)
Loss from unconsolidated affiliate investments		(4.6)	(1.2)	(4.7)	(2.3)
Other income		0.4	0.2	0.4	0.3
Income before non-controlling interest and income taxes		108.9	122.6	214	191.8
Capital expenditures		104.7	62.5	218.8	122.5
Permian
Segment Reporting
Revenue from contracts with customers		627.3	1,118.1	1,226.2	2,011.4
Realized gain (loss) on derivatives		5.4	(10.2)	1.4	(12.6)
Change in fair value of interest rate swaps		(7.9)	12.5	(1.6)	6.6
Total revenues		624.8	1,120.4	1,226	2,005.4
Cost of sales, exclusive of operating expenses and depreciation and amortization		(479.9)	(958)	(937)	(1,724.7)
Adjusted gross margin		144.9	162.4	289	280.7
Operating expenses		(53.1)	(50.3)	(101.2)	(95.6)
Segment profit		91.8	112.1	187.8	185.1
Depreciation and amortization		(41.5)	(37.1)	(81.5)	(73.8)
Gross margin		50.3	75	106.3	111.3
Gain on disposition of assets		0.1	0	0.1	0
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt			0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		50.4	75	106.4	111.3
Capital expenditures		51.6	34.7	108.3	68.9
Louisiana
Segment Reporting
Revenue from contracts with customers		841.1	1,633.7	1,946.8	3,158.1
Realized gain (loss) on derivatives		(7.8)	(2.5)	(0.6)	(9.1)
Change in fair value of interest rate swaps		18.2	11.8	9.2	6.2
Total revenues		851.5	1,643	1,955.4	3,155.2
Cost of sales, exclusive of operating expenses and depreciation and amortization		(715)	(1,519.2)	(1,688.9)	(2,907.9)
Adjusted gross margin		136.5	123.8	266.5	247.3
Operating expenses		(32)	(34.8)	(65.6)	(67.8)
Segment profit		104.5	89	200.9	179.5
Depreciation and amortization		(36.9)	(39.4)	(75.2)	(74.9)
Gross margin		67.6	49.6	125.7	104.6
Gain on disposition of assets		0.1	0	0.2	0.2
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt			0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		67.7	49.6	125.9	104.8
Capital expenditures		17.7	6.3	30	12
Oklahoma
Segment Reporting
Revenue from contracts with customers		264.3	450.6	577.1	845
Realized gain (loss) on derivatives		1.9	(15.8)	3.9	(19.5)
Change in fair value of interest rate swaps		2	8.2	0.6	1.1
Total revenues		268.2	443	581.6	826.6
Cost of sales, exclusive of operating expenses and depreciation and amortization		(130.5)	(321.3)	(324.5)	(598.1)
Adjusted gross margin		137.7	121.7	257.1	228.5
Operating expenses		(27)	(23.1)	(51.7)	(44.1)
Segment profit		110.7	98.6	205.4	184.4
Depreciation and amortization		(56.6)	(52.3)	(108.5)	(103.2)
Gross margin		54.1	46.3	96.9	81.2
Gain on disposition of assets		0.1	0.2	0.3	0.4
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt			0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		54.2	46.5	97.2	81.6
Capital expenditures		22.1	11.5	47.8	26.9
North Texas
Segment Reporting
Revenue from contracts with customers		167.6	276.8	348.5	518.7
Realized gain (loss) on derivatives		6.5	(2.3)	14.6	(5.7)
Change in fair value of interest rate swaps		(7)	2.8	(4.3)	6.3
Total revenues		167.1	277.3	358.8	519.3
Cost of sales, exclusive of operating expenses and depreciation and amortization		(75.1)	(189.7)	(164.7)	(347.1)
Adjusted gross margin		92	87.6	194.1	172.2
Operating expenses		(24.7)	(20.7)	(50.7)	(42.3)
Segment profit		67.3	66.9	143.4	129.9
Depreciation and amortization		(29)	(28.7)	(57.8)	(57.1)
Gross margin		38.3	38.2	85.6	72.8
Gain on disposition of assets		0.5	0.2	0.6	(5.3)
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt			0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		38.8	38.4	86.2	67.5
Capital expenditures		11.8	8.1	29.9	11.2
Corporate
Segment Reporting
Revenue from contracts with customers		(381.5)	(883.1)	(824.2)	(1,678.2)
Realized gain (loss) on derivatives		0	0	0	0
Change in fair value of interest rate swaps		0	0	0	0
Total revenues		(381.5)	(883.1)	(824.2)	(1,678.2)
Cost of sales, exclusive of operating expenses and depreciation and amortization		381.5	883.1	824.2	1,678.2
Adjusted gross margin		0	0	0	0
Operating expenses		0	0	0	0
Segment profit		0	0	0	0
Depreciation and amortization		(1.3)	(1.5)	(2.7)	(2.9)
Gross margin		(1.3)	(1.5)	(2.7)	(2.9)
Gain on disposition of assets		0	0	0	0
General and administrative		(27.9)	(28.4)	(57.4)	(57.4)
Interest expense, net of interest income		(68.8)	(55.5)	(137.3)	(110.6)
Gain on extinguishment of debt			(0.5)		(0.5)
Loss from unconsolidated affiliate investments		(4.6)	(1.2)	(4.7)	(2.3)
Other income		0.4	0.2	0.4	0.3
Income before non-controlling interest and income taxes		(102.2)	(86.9)	(201.7)	(173.4)
Capital expenditures		1.5	1.9	2.8	3.5
Product sales
Segment Reporting
Revenue from contracts with customers		1,239.3	2,370.5	2,715.6	4,414.4
Product sales | Permian
Segment Reporting
Revenue from contracts with customers		370.8	654.6	687.2	1,122.2
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers		793.7	1,546.6	1,840	2,983.5
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		60	131.3	160.1	245.4
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers		14.8	38	28.3	63.3
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Natural gas sales
Segment Reporting
Revenue from contracts with customers		218.5	720.9	560.9	1,229.7
Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers		76.4	323	205.7	518.6
Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers		92.5	272.9	224.3	484.4
Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		32.9	87.1	99.7	163.4
Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers		16.7	37.9	31.2	63.3
Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
NGL sales
Segment Reporting
Revenue from contracts with customers		647.1	1,167.4	1,513	2,321.9
NGL sales | Permian
Segment Reporting
Revenue from contracts with customers		0	0	0.4	0
NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers		648.6	1,163.7	1,506.5	2,315.2
NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.4	3.6	9	6.7
NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers		(1.9)	0.1	(2.9)	0
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		373.7	482.2	641.7	862.8
Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers		294.4	331.6	481.1	603.6
Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers		52.6	110	109.2	183.9
Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		26.7	40.6	51.4	75.3
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		204.1	427.5	441.6	827.3
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		5.3	43.1	9.7	80
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		102.3	242.6	220.3	451
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		69	169.8	151.2	319.7
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(380.7)	(883)	(822.8)	(1,678)
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		204.1	427.5	441.6	827.3
NGL sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		5.3	43.1	9.7	80
NGL sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		102.3	242.6	220.3	450.7
NGL sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		66.2	165.8	145.7	312.7
NGL sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(377.9)	(879)	(817.3)	(1,670.7)
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	0.3
Crude oil and condensate sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		2.8	4	5.5	7
Crude oil and condensate sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(2.8)	(4)	(5.5)	(7.3)
Midstream services
Segment Reporting
Revenue from contracts with customers		279.5	225.6	558.8	440.6
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers		52.4	36	97.4	61.9
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers		42.1	44	97.1	94.5
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers		102	76.6	196.7	148.5
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers		83	69	167.6	135.7
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Gathering and transportation
Segment Reporting
Revenue from contracts with customers		160.4	120.9	310.6	232.3
Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers		29.3	19.9	52.6	33.5
Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers		18.7	15.7	38.7	32
Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers		60.5	44.7	115.3	87.4
Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers		51.9	40.6	104	79.4
Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Processing
Segment Reporting
Revenue from contracts with customers		81.5	66.7	163.2	128
Processing | Permian
Segment Reporting
Revenue from contracts with customers		14.5	9.9	28.5	17.7
Processing | Louisiana
Segment Reporting
Revenue from contracts with customers		0.1	0.3	0.4	0.8
Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers		36.4	28.6	71.7	54
Processing | North Texas
Segment Reporting
Revenue from contracts with customers		30.5	27.9	62.6	55.5
Processing | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
NGL services
Segment Reporting
Revenue from contracts with customers		17.5	18.5	45.3	42.4
NGL services | Permian
Segment Reporting
Revenue from contracts with customers		0	0	0	0
NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers		17.4	18.4	45.2	42.3
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		0.1	0.1	0.1	0.1
NGL services | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Crude services
Segment Reporting
Revenue from contracts with customers		17.7	18.6	34.9	36.2
Crude services | Permian
Segment Reporting
Revenue from contracts with customers		7	6	13	10.3
Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers		5.6	9.2	12.1	18.6
Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers		4.9	3.2	9.4	6.9
Crude services | North Texas
Segment Reporting
Revenue from contracts with customers		0.2	0.2	0.4	0.4
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	0.9	4.8	1.7
Other services | Permian
Segment Reporting
Revenue from contracts with customers		1.6	0.2	3.3	0.4
Other services | Louisiana
Segment Reporting
Revenue from contracts with customers		0.3	0.4	0.7	0.8
Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.2	0.1	0.3	0.2
Other services | North Texas
Segment Reporting
Revenue from contracts with customers		0.3	0.2	0.5	0.3
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	0.1
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0	0.1	0	0.1
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0.8	0	1.4	0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		$ (0.8)	(0.1)	(1.4)	(0.2)
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				0.8	1.4
NGL services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers				$ (0.8)	(1.4)
Crude services—related parties
Segment Reporting
Revenue from contracts with customers			0		0
Crude services—related parties | Permian
Segment Reporting
Revenue from contracts with customers			0		0
Crude services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers			0		0
Crude services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers			0.1		0.1
Crude services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers			0		0
Crude services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers			$ (0.1)		(0.1)
Other services—related parties
Segment Reporting
Revenue from contracts with customers					0
Other services—related parties | Permian
Segment Reporting
Revenue from contracts with customers					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
Other services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers					0
Other services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers					$ (0.1)
[1]Includes related party cost of sales of $2.5 million and $9.1 million for the three months ended June 30, 2023 and 2022, respectively, and $4.0 million and $19.7 million for the six months ended June 30, 2023 and 2022, respectively.

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Segment Reporting
Total identifiable assets	$ 8,399.9	$ 8,651
Permian
Segment Reporting
Total identifiable assets	2,708.3	2,661.4
Louisiana
Segment Reporting
Total identifiable assets	2,077.6	2,310.7
Oklahoma
Segment Reporting
Total identifiable assets	2,350.4	2,420.4
North Texas
Segment Reporting
Total identifiable assets	1,038.9	1,094.6
Corporate
Segment Reporting
Total identifiable assets	$ 224.7	$ 163.9

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Jun. 30, 2023	Dec. 31, 2022
Other current assets:
Natural gas and NGLs inventory	$ 74.9	$ 147.1
Prepaid expenses and other	26.4	19.5
Other current assets	101.3	166.6
Other current liabilities:
Accrued interest	64.3	57.6
Accrued wages and benefits, including taxes	15.3	38.1
Accrued ad valorem taxes	26.1	32
Accrued settlement Of mandatorily redeemable non-controlling interest	0	10.5
Capital expenditure accruals	42.7	23.4
Short-term lease liability	26.6	26.2
Operating expense accruals	19.7	18.5
Other	44.1	23.3
Other current liabilities	$ 238.8	$ 229.6

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2023 USD ($) defendant claim
Koch | EnLink Gas Marketing, LP
Commitments and Contingencies
Loss contingency, damages sought, value | $	$ 53.9
Harris County Multi-District Litigation | EnLink Energy GP, LLC
Commitments and Contingencies
Number of defendants | defendant	350
Filed cases, over	150
Third party claims, number	90