EnLink Midstream (ENLC) 10-Q 7 Aug 24 2024 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2024	Aug. 01, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2024
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)		461,449,461
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2024
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, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents		$ 5.8	$ 28.7
Accounts receivable:
Trade receivables	[1]	59.9	85.9
Accrued revenue and other		583.3	581.4
Fair value of derivative assets		62.5	76.9
Other current assets		102.7	65.4
Total current assets		814.2	838.3
Property and equipment, net of accumulated depreciation of $5,357.9 and $5,137.2, respectively		6,313.4	6,407
Intangible assets, net of accumulated amortization of $1,114.9 and $1,051.2, respectively		729.9	793.6
Investment in unconsolidated affiliates		162.8	150.5
Fair value of derivative assets—long-term		11.3	27
Other assets, net		120.7	112.2
Total assets		8,152.3	8,328.6
Current liabilities:
Accounts payable and drafts payable		86.9	126.5
Accrued natural gas, NGLs, condensate, and crude oil purchases		433.2	428
Fair value of derivative liabilities		64.1	62.7
Current maturities of long-term debt		421.2	97.9
Other current liabilities		249.3	278.5
Total current liabilities		1,254.7	993.6
Long-term debt, net of unamortized issuance cost		4,236.2	4,471
Other long-term liabilities		79	98
Deferred tax liability, net		111	104.2
Fair value of derivative liabilities		13.1	26.7
Members’ equity:
Members’ equity (452,144,847 and 451,614,086 units issued and outstanding, respectively)		914.2	1,000.5
Accumulated other comprehensive income		3.8	0.7
Non-controlling interest		1,540.3	1,633.9
Total members’ equity		2,458.3	2,635.1
Commitments and contingencies (Note 13)
Total liabilities and members’ equity		$ 8,152.3	$ 8,328.6
[1] There was no allowance for bad debt at June 30, 2024 and December 31, 2023.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
ASSETS
Property and equipment, accumulated depreciation	$ 5,357.9	$ 5,137.2
Intangible assets, accumulated amortization	$ 1,114.9	$ 1,051.2
Members’ equity:
Common units issued (in shares)	452,144,847	451,614,086
Common units outstanding (in shares)	451,614,086	452,144,847
Allowance for bad debt	$ 0	$ 0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Revenues:
Revenue from contracts with customers	$ 1,551.9	$ 1,518.8	$ 3,228.8	$ 3,274.4
Revenue, Product and Service [Extensible Enumeration]	Midstream services	Midstream services	Midstream services	Midstream services
Gain (loss) on derivative activity	$ (0.8)	$ 11.3	$ (29.8)	$ 23.2
Total revenues	1,551.1	1,530.1	3,199	3,297.6
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	$ 1,062.6	$ 1,019	$ 2,213	$ 2,290.9
Cost, Product and Service [Extensible Enumeration]	Midstream services	Midstream services	Midstream services	Midstream services
Operating expenses	$ 155.2	$ 136.8	$ 307.8	$ 269.2
Depreciation and amortization	162.6	165.3	327.9	325.7
Impairments	0	0	14.2	0
(Gain) loss on disposition of assets	0.9	(0.8)	(0.8)	(1.2)
General and administrative	30.2	27.9	85.4	57.4
Total operating costs and expenses	1,411.5	1,348.2	2,947.5	2,942
Operating income	139.6	181.9	251.5	355.6
Other income (expense):
Interest expense, net of interest income	(66.7)	(68.8)	(132.1)	(137.3)
Income (loss) from unconsolidated affiliate investments	0.3	(4.6)	(0.5)	(4.7)
Other income	3.8	0.4	4.3	0.4
Total other expense	(62.6)	(73)	(128.3)	(141.6)
Income (loss) before non-controlling interest and income taxes	77	108.9	123.2	214
Income tax expense	(10)	(19)	(6.2)	(29.9)
Net income	67	89.9	117	184.1
Net income attributable to non-controlling interest	28.9	35.6	64.4	71.6
Net income attributable to ENLC	$ 38.1	$ 54.3	$ 52.6	$ 112.5
Net income attributable to ENLC per unit:
Basic common unit (in dollars per share)	$ 0.07	$ 0.12	$ 0.11	$ 0.24
Diluted common unit (in dollars per share)	$ 0.07	$ 0.12	$ 0.10	$ 0.24
Product sales
Revenues:
Revenue from contracts with customers	$ 1,278.6	$ 1,239.3	$ 2,683.6	$ 2,715.6
Midstream services
Revenues:
Revenue from contracts with customers	$ 273.3	$ 279.5	$ 545.2	$ 558.8

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2024		Jun. 30, 2023		Jun. 30, 2024		Jun. 30, 2023
Statement of Comprehensive Income [Abstract]
Net income		$ 67		$ 89.9		$ 117		$ 184.1
Unrealized gain on designated cash flow hedge	[1]	0.1	[2]	5.7	[3]	3.1	[4]	4.5	[5]
Comprehensive income		67.1		95.6		120.1		188.6
Comprehensive income attributable to non-controlling interest		28.9		35.6		64.4		71.6
Comprehensive income attributable to ENLC		$ 38.2		$ 60		$ 55.7		$ 117
[1] Includes tax expense of $0.2 million and $1.1 million for the three and six months ended June 30, 2024, respectively, and tax expense of $1.8 million and $1.4 million for the three and six months ended June 30, 2023, respectively. Includes tax expense of $0.2 million for the three months ended June 30, 2024. Includes tax expense of $1.8 million for the three months ended June 30, 2023. Includes tax expense of $1.1 million for the six months ended June 30, 2024. Includes tax expense of $1.4 million for the six 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, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Statement of Comprehensive Income [Abstract]
Tax expense	$ 0.2	$ 1.8	$ 1.1	$ 1.4

Consolidated Statement of Chang

Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Series B Preferred Stock	Repurchase of Series C Preferred Units	Common Units		Common Units Series B Preferred Stock	Accumulated Other Comprehensive Income (Loss)	Non-Controlling Interest	Non-Controlling Interest Series B Preferred Stock	Non-Controlling Interest Repurchase of Series C Preferred Units
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						469,000,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(16.9)				$ (16.9)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)						2,600,000
Unit-based compensation		8.5				$ 8.5
Contributions from non-controlling interests		22.1								22.1
Distributions		(202.7)				(120.2)				(82.5)
Unrealized gain on designated cash flow hedge	[2]	4.5	[1]						4.5
Adjustment related to the redemption of the mandatorily redeemable non-controlling interest	[3]	0.8				0.8
Loss on exchange of Series B Preferred Units / Repurchase of Series C Preferred Units					$ (3.9)							$ (3.9)
Common units repurchased		$ (107.5)				$ (107.5)
Common units repurchased (in shares)		(9,585,796)				(9,600,000)
Accrued common unit repurchase	[4]	$ (27.5)				$ (27.5)
Net income		184.1				112.5				71.6
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						462,000,000
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 on designated cash flow hedge	[5]	5.7	[1]						5.7
Adjustment related to the redemption of the mandatorily redeemable non-controlling interest	[6]	0.8				0.8
Common units repurchased		$ (56.1)				$ (56.1)
Common units repurchased (in shares)		(5,141,381)				(5,200,000)
Accrued common unit repurchase	[7]	$ (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						462,000,000
Member equity, beginning balance at Dec. 31, 2023		$ 2,635.1				$ 1,000.5			0.7	1,633.9
Units outstanding, beginning balance (in shares) at Dec. 31, 2023		451,614,086				451,600,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		$ (17.1)				$ (17.1)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)						2,800,000
Unit-based compensation		10.8				$ 10.8
Contributions from non-controlling interests		13.8								13.8
Distributions		(204.4)				(122.5)				(81.9)
Unrealized gain on designated cash flow hedge	[8]	3.1	[1]						3.1
Exchange of Series B Preferred Units				$ 5.2				$ 95.1			$ (89.9)
Exchange of Series B Preferred Units (in shares)								7,000,000
Loss on exchange of Series B Preferred Units / Repurchase of Series C Preferred Units				(5.2)				$ (5.2)
Common units repurchased	[9]	$ (77.1)				$ (77.1)
Common units repurchased (in shares)		(9,345,294)				(9,300,000)	[9]
Accrued common unit repurchase	[10]	$ (22.9)				$ (22.9)
Net income		117				52.6				64.4
Member equity, end balance at Jun. 30, 2024		$ 2,458.3				$ 914.2			3.8	1,540.3
Units outstanding, ending balance (in shares) at Jun. 30, 2024		452,144,847				452,100,000
Member equity, beginning balance at Mar. 31, 2024		$ 2,539.1				$ 892.5			3.7	1,642.9
Units outstanding, beginning balance (in shares) at Mar. 31, 2024						448,800,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(1.6)				$ (1.6)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)						200,000
Unit-based compensation		5.2				$ 5.2
Contributions from non-controlling interests		0.8								0.8
Distributions		(102.5)				(60.1)				(42.4)
Unrealized gain on designated cash flow hedge	[11]	0.1	[1]						0.1
Exchange of Series B Preferred Units				5.2				$ 95.1			$ (89.9)
Exchange of Series B Preferred Units (in shares)								7,000,000
Loss on exchange of Series B Preferred Units / Repurchase of Series C Preferred Units				$ (5.2)				$ (5.2)
Common units repurchased		$ (50)				$ (50)
Common units repurchased (in shares)		(3,897,852)				(3,900,000)
Accrued common unit repurchase	[12],[13]	$ (0.2)				$ (0.2)
Net income		67				38.1				28.9
Member equity, end balance at Jun. 30, 2024		$ 2,458.3				$ 914.2			$ 3.8	$ 1,540.3
Units outstanding, ending balance (in shares) at Jun. 30, 2024		452,144,847				452,100,000
[1] Includes tax expense of $0.2 million and $1.1 million for the three and six months ended June 30, 2024, respectively, and tax expense of $1.8 million and $1.4 million for the three and six months ended June 30, 2023, respectively. Includes tax expense of $1.4 million for the six months ended June 30, 2023. Relates to book-to-tax differences recorded upon the settlement of the mandatorily redeemable non-controlling interest. Relates to the repurchase of ENLC common units held by GIP, which are contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.” Includes tax expense of $1.8 million for the three months ended June 30, 2023. Relates to book-to-tax differences recorded upon the settlement of the mandatorily redeemable non-controlling interest. Relates to the change in the repurchase accrual of ENLC common units held by GIP, which are contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.” Includes tax expense of $1.1 million for the six months ended June 30, 2024. Excludes the $41.5 million repurchase of ENLC common units held by GIP on February 19, 2024, which was accrued at December 31, 2023. Relates to the repurchase of ENLC common units held by GIP, which are contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.” Includes tax expense of $0.2 million for the three months ended June 30, 2024. Excludes the $23.1 million repurchase of ENLC common units held by GIP on April 29, 2024, which was accrued at March 31, 2024. Relates to the change in the repurchase accrual of ENLC common units held by GIP, which are contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.”

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]
Stock repurchased	$ 23.1	$ 41.5

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Cash flows from operating activities:
Net income	$ 117	$ 184.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	327.9	325.7
Gain on disposition of assets	(0.8)	(1.2)
Non-cash unit-based compensation	10.8	8.5
Non-cash (gain) loss on derivatives recognized in net income	22.1	(3.9)
Amortization of debt issuance costs and net discount of senior unsecured notes	3	3.3
Deferred income tax expense	5.8	29.6
Loss from unconsolidated affiliate investments	0.5	4.7
Impairments	14.2	0
Other operating activities	(2.1)	2.3
Changes in assets and liabilities, net of the effects of acquisitions:
Accounts receivable, accrued revenue, and other	24.5	183.1
Product inventory, prepaid expenses, and other	(36)	66.6
Accounts payable, accrued product purchases, and other accrued liabilities	(31)	(215)
Net cash provided by operating activities	455.9	587.8
Cash flows from investing activities:
Additions to property and equipment	(210.8)	(203.1)
Contributions to unconsolidated affiliate investments	(20.1)	(49.7)
Other investing activities	(3.2)	3.7
Net cash used in investing activities	(234.1)	(249.1)
Cash flows from financing activities:
Proceeds from borrowings	1,377.5	2,004.1
Repayments on borrowings	(1,292)	(1,989)
Distributions to members	(122.5)	(120.2)
Distributions to non-controlling interests	(81.9)	(82.5)
Earnout payments	(2.5)	0
Payment to redeem mandatorily redeemable non-controlling interest	0	(10.5)
Contributions from non-controlling interests	13.8	22.1
Common unit repurchases	(118.6)	(107.5)
Payment of taxes related to the conversion of unit-based awards for common units	(17.1)	(16.9)
Other financing activities	(1.4)	(2.2)
Net cash used in financing activities	(244.7)	(306.5)
Net increase (decrease) in cash and cash equivalents	(22.9)	32.2
Cash and cash equivalents, beginning of period	28.7	22.6
Cash and cash equivalents, end of period	5.8	54.8
Supplemental disclosures of cash flow information:
Cash paid for interest	133.6	131.1
Cash paid for income taxes	0.6	1
Non-cash investing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	28.2	11.6
Non-cash accrual of property and equipment	(21.2)	15.7
Non-cash financing activities:
Issuance of ENLC common units from Series B Preferred Units exchange	95.1	0
Redemption of Series B Preferred Units from Series B Preferred Units exchange	(89.9)	0
Repurchase of Series C Preferred Units
Cash flows from financing activities:
Repurchase of Series C Preferred Units	$ 0	$ (3.9)

General

General	6 Months Ended
	Jun. 30, 2024
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, 2024, GIP, through GIP III Stetson I, L.P. and GIP III Stetson II, L.P, owns 45.0% 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 owning, operating, investing in, and developing midstream energy infrastructure assets to provide midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, storing, trans-loading, and selling crude oil and condensate. As of June 30, 2024, our midstream infrastructure network includes approximately 13,600 miles of pipelines, 25 natural gas processing plants with approximately 5.9 Bcf/d of processing capacity, seven fractionators with approximately 316,300 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

Significant Accounting Policies

Significant Accounting Policies	6 Months Ended
	Jun. 30, 2024
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, 2023 filed with the Commission on February 21, 2024. 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. 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 (1) 2024 (remaining) $ 85.3 2025 157.1 2026 159.3 2027 130.9 2028 127.1 Thereafter 1,133.5 Total $ 1,793.2 ____________________________ (1) The contractually committed fees include $19.8 million in 2025, $33.8 million in 2026, $33.7 million in 2027, $33.8 million in 2028, and $722.9 million from 2029 through 2050 for MVCs under our transportation services agreement with a subsidiary of ExxonMobil. We may not realize the full value of these fees or realize them in different periods under any financial arrangement entered into in respect of the Pecan Island transportation agreement. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other Recent Developments” for additional information. c. Property and Equipment In accordance with ASC 360 , Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances, or triggering events, indicate that their carrying value may not be recoverable. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. During the first quarter of 2024, we identified changes in our outlook for future cash flows and the anticipated use of certain non-core assets in our North Texas segment. We determined that the carrying amounts of these assets exceeded their fair values, based on market inputs and certain assumptions, and recorded an impairment expense of $14.2 million for the three months ended March 31, 2024. In April 2024, we sold these non-core assets in our North Texas segment. We did not record any impairment expense for the three months ended June 30, 2024 and the three and six months ended June 30, 2023. d. Non-controlling Interests Our non-controlling interests are comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50.0% share of the Ascension JV. Certain of our joint venture arrangements provide us or our joint venture partners with the right, under certain circumstances, to cause a purchase or sale of interest in the joint venture or to seek to sell the entire joint venture. At any time after June 30, 2025, NGP has the right to arrange a sale of the Delaware Basin JV for the best available price; provided that, if NGP exercises this right, we are permitted, but not required, to purchase NGP’s interest at a certain call price. e. Recent Accounting Pronouncements On November 27, 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” (“ASU 2023-07”). ASU 2023-07 amends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The impact of ASU 2023-07 would be limited to the disclosures within the footnotes of the consolidated financial statements. On December 14, 2023, the FASB issued ASU No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” (“ASU 2023-09”). ASU 2023-09 is intended to improve the transparency of income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. ASU 2023-09 will become effective for annual periods beginning after December 15, 2024, with early adoption permitted. Management is currently evaluating ASU 2023-09 to determine its impact on the Company’s annual disclosures.

Intangible Assets

Intangible Assets	6 Months Ended
	Jun. 30, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	(3) Intangible Assets Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years. The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Six Months Ended June 30, 2024 Customer relationships, beginning of period $ 1,844.8 $ (1,051.2) $ 793.6 Amortization expense — (63.7) (63.7) Customer relationships, end of period $ 1,844.8 $ (1,114.9) $ 729.9 Amortization expense was $31.9 million for each of the three months ended June 30, 2024 and 2023 and $63.7 million and $63.8 million for the six months ended June 30, 2024 and 2023, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2024 (remaining) $ 63.9 2025 110.2 2026 106.3 2027 106.3 2028 106.3 Thereafter 236.9 Total $ 729.9

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2024
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions (a) Transactions with the Cedar Cove JV We process natural gas and purchase the related residue natural gas and NGLs from the Cedar Cove JV. We recorded the following amounts (in millions) on our consolidated balance sheets related to our transactions with the Cedar Cove JV: June 30, 2024 December 31, 2023 Accrued natural gas, NGLs, condensate, and crude oil purchases $ 0.3 $ 0.3 We recorded the following amounts (in millions) on our consolidated statements of operations related to our transactions with the Cedar Cove JV: Three Months Ended Six Months Ended 2024 2023 2024 2023 Midstream services revenue $ 0.5 $ 0.6 $ 1.0 $ 1.3 Cost of sales, exclusive of operating expenses and depreciation and amortization (1.4) (2.5) (2.8) (4.0) (b) Transactions with GIP GIP Repurchase Agreement. On January 16, 2024, we entered into a new repurchase agreement with GIP with terms substantially similar to the repurchase agreement with GIP for 2023 entered into on December 20, 2022, which repurchase agreement terminated on December 31, 2023 in accordance with its terms. The current repurchase agreement will renew for successive one-year terms (each, a “Renewal Year”) on January 1 of each Renewal Year, with the first Renewal Year beginning on January 1, 2025, unless either the Company or the GIP Entities elects to terminate the Repurchase Agreement prior to the start of any Renewal Year, during a two-week period in December preceding the applicable Renewal Year. See “Note 8—Members’ Equity” for additional information on the activity related to the GIP repurchase agreement.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2024
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of June 30, 2024 and December 31, 2023, long-term debt consisted of the following (in millions): June 30, 2024 December 31, 2023 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ 229.0 $ — $ 229.0 $ — $ — $ — AR Facility due 2025 (2) 254.4 — 254.4 300.0 — 300.0 ENLK’s 4.40% Senior unsecured notes due 2024 — — — 97.9 — 97.9 ENLK’s 4.15% Senior unsecured notes due 2025 421.6 — 421.6 421.6 — 421.6 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.1) 490.9 491.0 (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 (2.5) 997.5 1,000.0 (2.7) 997.3 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 (4.9) 445.1 450.0 (5.0) 445.0 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 $ 4,694.7 $ (7.8) 4,686.9 $ 4,609.2 $ (8.2) 4,601.0 Debt issuance cost (3) (29.5) (32.1) Less: Current maturities of long-term debt (4)(5) (421.2) (97.9) Long-term debt, net of unamortized issuance cost $ 4,236.2 $ 4,471.0 ____________________________ (1) The effective interest rate was 6.9% at June 30, 2024. (2) The effective interest rate was 6.3% and 6.4% at June 30, 2024 and December 31, 2023, respectively. (3) Net of accumulated amortization of $22.6 million and $20.0 million at June 30, 2024 and December 31, 2023, respectively. (4) The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes are classified as “Current maturities of long-term debt” in the consolidated balance sheet as of December 31, 2023 as these notes matured on April 1, 2024. (5) The outstanding balance, net of debt issuance costs, of ENLK’s 4.15% senior unsecured notes are classified as “Current maturities of long-term debt” in the consolidated balance sheet as of June 30, 2024 as these notes mature on June 1, 2025. Revolving Credit Facility The Revolving Credit Facility permits ENLC to borrow up to $1.4 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. There were $229.0 million in outstanding borrowings under the Revolving Credit Facility and $14.6 million in outstanding letters of credit as of June 30, 2024. At June 30, 2024, 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 $600.6 million as of June 30, 2024. As of June 30, 2024, the AR Facility had a borrowing base of $345.5 million and there were $254.4 million in outstanding borrowings under the AR Facility. The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations. Depending on our operational needs, we may not borrow the total amount available for borrowings. At June 30, 2024, 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.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
Income Taxes	(6) Income Taxes The components of our income tax expense are as follows (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Current income tax expense $ (0.2) $ (0.2) $ (0.4) $ (0.3) Deferred income tax expense (9.8) (18.8) (5.8) (29.6) Income tax expense $ (10.0) $ (19.0) $ (6.2) $ (29.9) The following schedule reconciles income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Expected income tax expense based on federal statutory tax rate $ (8.3) $ (15.4) $ (10.5) $ (29.9) State income tax expense, net of federal benefit (1.1) (2.0) (1.5) (3.8) Unit-based compensation (1) 0.4 0.1 7.7 6.6 Other (1.0) (1.7) (1.9) (2.8) Income tax expense $ (10.0) $ (19.0) $ (6.2) $ (29.9) ____________________________ (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, 2024, we had $784.9 million of deferred tax assets, net of a $1.2 million valuation allowance, and $895.9 million of deferred tax liabilities for net deferred tax liabilities of $111.0 million. As of December 31, 2023, we had $758.3 million of deferred tax assets, net of a $1.2 million valuation allowance, and $862.5 million of deferred tax liabilities for net deferred tax liabilities of $104.2 million. As of June 30, 2024, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

Certain Provisions of the ENLK

Certain Provisions of the ENLK Partnership Agreement	6 Months Ended
	Jun. 30, 2024
Partners' Capital [Abstract]
Certain Provisions of the ENLK Partnership Agreement	(7) Certain Provisions of the ENLK Partnership Agreement a. Series B Preferred Units As of June 30, 2024 and December 31, 2023, there were 48,760,039 and 54,575,638 Series B Preferred Units issued and outstanding, respectively. Conversion Series B Preferred Units are exchangeable for ENLC common units in an amount equal to the number of applicable Series B Preferred Units multiplied by the exchange ratio of 1.15, subject to certain adjustments. The exchange is subject to ENLK’s option to pay cash instead of ENLC issuing additional ENLC common units, and can occur in whole or in part at the option of the holder of the Series B Preferred Units at any time, or in whole at our option, provided the daily volume-weighted average closing price of the ENLC common units for the 30 trading days ending two A summary of the exchange activity by the holders of the Series B Preferred Units during the three months ended June 30, 2024 is provided below (in millions, except per unit amounts): Series B Preferred Units Canceled Series B Preferred Units Exchanged ENLC Common Units Issued Loss on Exchange of Series B Preferred Units Transaction date Units Units $ Units $ $ April 2024 2,604,046 2,608,696 (1) $ 38.3 3,000,000 $ 41.2 $ (2.9) May 2024 3,478,262 3,478,262 $ 51.6 4,000,000 $ 53.9 $ (2.3) ____________________________ (1) Includes 4,650 accrued and unpaid Series B Preferred Units that holders were entitled to receive in a PIK Distribution in respect of the first quarter of 2024 as of the date of the exchange of such Series B Preferred Units. In July 2024, the holders of the Series B Preferred Units exchanged 8,695,654 Series B Preferred Units into 10,000,000 ENLC common units. Additionally, on August 5, 2024, we purchased 12,698,414 Series B Preferred Units for $200.2 million. Subsequent to these post-quarter exchanges and the unit purchase, there were 27,365,971 outstanding Series B Preferred Units as of August 7, 2024, the date of this report. Transfer Fee Holders of Series B Preferred Units must pay a $0.15 fee (A) on each Series B Preferred Unit that is transferred to (i) anyone other than an affiliate of such holder or (ii) another holder, or (B) following the exchange of each Series B Preferred Unit into an ENLC common unit, upon the sale of each ENLC common unit in a registered offering. An initial non-refundable fee of $3.5 million, which will be credited against and reduce any fees payable upon a subsequent transfer or registered sale, was received from the holders of the Series B Preferred Units in May 2024 in connection with the exchange of Series B Preferred Units in April 2024, and was recorded as “Other income” in the consolidated statements of operations for the three and six months ended June 30, 2024. Income and 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, 2024 and 2023 is provided below: Declaration period PIK Distribution Cash distribution (in millions) Date paid/payable 2024 Fourth Quarter of 2023 136,439 $ 15.3 February 9, 2024 First Quarter of 2024 130,270 $ 14.7 May 14, 2024 Second Quarter of 2024 (1) — $ 12.8 August 14, 2024 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 ____________________________ (1) On September 8, 2023, we amended and restated the limited partnership agreement of ENLK (the “ENLK LPA”) to terminate the rights of the holders of the Series B Preferred Units to receive PIK distributions beginning with the quarter ending June 30, 2024, and in connection with such termination of PIK distributions, increase the cash distribution per Series B Preferred Unit from $0.28125 to $0.31875, in addition to the continued payment of the Series B Excess Cash Payment Amount (as defined in the ENLK LPA). Allocation of Taxable Income to the Series B Preferred Units 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 the positive net income of ENLK for the allocation year (the “Allocation Cap”). As of June 30, 2024, 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 $7.32 per Series B Preferred Unit (the “Catch-Up 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 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, 2024 and December 31, 2023, there were 366,500 Series C Preferred Units issued and outstanding. 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 is provided below: Declaration period (1) Distribution rate (2) Cash distribution (in millions) Date paid/payable 2024 December 15, 2023 – March 14, 2024 9.749 % $ 9.0 March 15, 2024 March 15, 2024 – June 14, 2024 9.701 % $ 9.1 June 17, 2024 June 15, 2024 – September 14, 2024 9.716 % $ 9.0 September 16, 2024 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 ____________________________ (1) Distributions on the Series C Preferred Units accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. (2) 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%. Starting on September 15, 2023, distributions on the Series C Preferred Units are based on the 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, 2024
Earnings Per Share [Abstract]
Members' Equity	(8) Members’ Equity a. Common Unit Repurchase Program The table below provides a summary of the Board’s authorizations of the 2023 and 2024 common unit repurchase programs. Date Board Action Authorized Amount December 2022 Reauthorization of common unit repurchase program and set amount available for repurchases for 2023 $ 200 November 2023 Increase in 2023 common unit repurchase program $ 50 December 2023 Reauthorization of common unit repurchase program and set amount available for repurchases for 2024 $ 200 July 2024 Increase in 2024 common unit repurchase program $ 50 ____________________________ (1) The authorized amount includes repurchases of common units held by GIP. Refer to “Note 4—Related Party Transactions” for more information on our ENLC common unit repurchase agreement with 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 2024 2023 2024 2023 Publicly held ENLC common units 2,035,157 3,230,504 4,201,962 5,437,809 ENLC common units held by GIP (1) 1,862,695 1,910,877 5,143,332 4,147,987 Total ENLC common units 3,897,852 5,141,381 9,345,294 9,585,796 Aggregate cost for publicly held ENLC common units $ 27.1 $ 32.2 $ 54.0 $ 59.0 Aggregate cost for ENLC common units held by GIP 23.1 23.2 64.6 47.8 Excise tax on common unit repurchases (0.2) 0.7 — 0.7 Total aggregate cost for ENLC common units $ 50.0 $ 56.1 $ 118.6 $ 107.5 Average price paid per publicly held ENLC common unit (2) $ 13.32 $ 9.96 $ 12.85 $ 10.85 Average price paid per ENLC common unit held by GIP (2)(3) $ 12.40 $ 12.12 $ 12.56 $ 11.53 ____________________________ (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 August 5, 2024, we repurchased 1,718,847 ENLC common units held by GIP at an aggregate cost of $22.9 million, or an average of $13.31 per common unit. These units represented GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended June 30, 2024. 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, 2024, $22.9 million is classified as “Other current liabilities” in the consolidated balance sheets related to our obligation to repurchase our common units from GIP. See “Note 4—Related Party Transactions” for additional information relating to the GIP repurchase agreement. 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 2024 2023 2024 2023 Distributed earnings allocated to: Common units (1) $ 59.8 $ 57.8 $ 119.6 $ 116.4 Unvested unit-based awards (1) 0.8 1.0 1.5 1.9 Total distributed earnings $ 60.6 $ 58.8 $ 121.1 $ 118.3 Distribution in excess of earnings: Common units $ (27.4) $ (4.4) $ (72.8) $ (5.7) Unvested unit-based awards (0.3) (0.1) (0.9) (0.1) Total distribution in excess of earnings $ (27.7) $ (4.5) $ (73.7) $ (5.8) Net income attributable to ENLC allocated to: Common units (2) $ 32.4 $ 53.4 $ 46.8 $ 110.7 Unvested unit-based awards (2) 0.5 0.9 0.6 1.8 Total net income attributable to ENLC (2) $ 32.9 $ 54.3 $ 47.4 $ 112.5 Net income attributable to ENLC per unit: Basic (2) $ 0.07 $ 0.12 $ 0.11 $ 0.24 Diluted (2) $ 0.07 $ 0.12 $ 0.10 $ 0.24 ____________________________ (1) Represents distribution activity consistent with the distribution activity table below. (2) Includes the loss on exchange of Series B Preferred Units. 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 2024 2023 2024 2023 Basic weighted average units outstanding: Weighted average common units outstanding 451.4 462.7 451.3 465.8 Diluted weighted average units outstanding: Weighted average basic common units outstanding 451.4 462.7 451.3 465.8 Dilutive effect of unvested restricted units 2.7 4.0 2.7 4.1 Total weighted average diluted common units outstanding 454.1 466.7 454.0 469.9 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, 2024 and 2023, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2024 Fourth Quarter of 2023 $ 0.1325 February 9, 2024 First Quarter of 2024 $ 0.1325 May 14, 2024 Second Quarter of 2024 $ 0.1325 August 14, 2024 2023 Fourth Quarter of 2022 $ 0.1250 February 13, 2023 First Quarter of 2023 $ 0.1250 May 12, 2023 Second Quarter of 2023 $ 0.1250 August 11, 2023

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(9) Derivatives Interest Rate Swap 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, including borrowings on the Revolving Credit Facility and the AR Facility. 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 a 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 our interest rate swap as a cash flow hedge in accordance with ASC 815, Derivatives and Hedging . There is no ineffectiveness related to our hedge. The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swap are as follows (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Change in fair value of interest rate swap $ 0.3 $ 7.5 $ 4.2 $ 5.9 Tax expense (0.2) (1.8) (1.1) (1.4) Unrealized gain on designated cash flow hedge $ 0.1 $ 5.7 $ 3.1 $ 4.5 The fair value of derivative assets and liabilities related to the interest rate swap are as follows (in millions): June 30, 2024 December 31, 2023 Fair value of derivative assets—current $ 4.4 $ 3.3 Fair value of derivative assets—long-term 0.7 — Fair value of derivative liabilities—long-term — (2.4) Net fair value of interest rate swap $ 5.1 $ 0.9 Interest income is recognized from accumulated other comprehensive income from the monthly settlement of our interest rate swap and was included in our consolidated statements of operations as follows (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Interest income $ 1.5 $ 1.1 $ 3.0 $ 1.6 We expect to recognize an additional $4.4 million of interest income out of accumulated other comprehensive income (loss) over the next twelve months. Commodity Derivatives We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations by utilizing various over-the-counter and exchange-traded commodity financial instrument contracts. Commodity swaps and futures are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swaps or futures as cash flow or fair value hedges for hedge accounting treatment under ASC 815, Derivatives and Hedging . Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our commodity risk management policy does not allow us to take speculative positions with our derivative contracts. We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs, and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced natural gas versus first-of-month priced natural gas. For condensate, crude oil, and natural gas, index swaps are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. Similarly, we use futures in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, crude, and condensate. For natural gas, NGLs, condensate, and crude oil, fixed-for-float swaps and futures are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party natural gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage. Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities, and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity on the consolidated statements of operations. We estimate the fair value of all of our derivative contracts based upon actively-quoted prices of the underlying commodities. 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 2024 2023 2024 2023 Change in fair value of derivatives $ 4.0 $ 5.3 $ (22.1) $ 3.9 Realized gain (loss) on derivatives (4.8) 6.0 (7.7) 19.3 Gain (loss) on derivative activity $ (0.8) $ 11.3 $ (29.8) $ 23.2 The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): June 30, 2024 December 31, 2023 Fair value of derivative assets—current $ 58.1 $ 73.6 Fair value of derivative assets—long-term 10.6 27.0 Fair value of derivative liabilities—current (64.1) (62.7) Fair value of derivative liabilities—long-term (13.1) (24.3) Net fair value of commodity derivatives $ (8.5) $ 13.6 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, 2024 (in millions, except volumes). The remaining term of the contracts extend no later than January 2029. Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps MMgals (126.4) $ (13.9) NGL (long contracts) Swaps MMgals 63.6 (0.1) Natural gas (short contracts) Swaps and futures Bbtu (116.7) 50.7 Natural gas (long contracts) Swaps and futures Bbtu 105.5 (45.7) Crude and condensate (short contracts) Swaps and futures MMbbls (6.6) (5.6) Crude and condensate (long contracts) Swaps and futures MMbbls 1.3 6.1 Total fair value of commodity derivatives $ (8.5) 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 $68.7 million as of June 30, 2024 would be reduced to $2.7 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, 2024
Fair Value Disclosures [Abstract]
Fair Value Measurements	(10) Fair Value Measurements Derivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2024 December 31, 2023 Interest rate swap (1) $ 5.1 $ 0.9 Commodity derivatives (2) $ (8.5) $ 13.6 ____________________________ (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. Long-term debt, including current maturities of long-term debt. The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions): June 30, 2024 December 31, 2023 Carrying Value Fair Carrying Value Fair Long-term debt, including current maturities of long-term debt (1) $ 4,657.4 $ 4,495.9 $ 4,568.9 $ 4,427.0 ____________________________ (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 $29.5 million and $32.1 million as of June 30, 2024 and December 31, 2023, respectively. The respective fair values do not factor in debt issuance costs. The fair values of all senior unsecured notes as of June 30, 2024 and December 31, 2023 were based on Level 2 inputs from third-party market quotations. 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.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2024
Segment Reporting [Abstract]
Segment Information	(11) Segment Information We manage and report our operations primarily according to the geography and the nature of the 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 transmission pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and, prior to its sale in November 2023, 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. 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, 2024 Natural gas sales $ 15.3 $ 110.9 $ 19.9 $ 31.4 $ — $ 177.5 NGL sales (6.2) 665.5 (0.6) (3.6) — 655.1 Crude oil and condensate sales 410.4 — 34.7 — — 445.1 Other — — — 0.9 — 0.9 Product sales 419.5 776.4 54.0 28.7 — 1,278.6 NGL sales—related parties 237.6 9.0 105.6 68.5 (420.7) — Crude oil and condensate sales—related parties — — — 3.6 (3.6) — Product sales—related parties 237.6 9.0 105.6 72.1 (424.3) — Gathering and transportation 41.6 27.9 64.7 41.0 — 175.2 Processing 14.5 0.6 35.4 21.9 — 72.4 NGL services — 13.9 — — — 13.9 Crude services 6.2 — 3.2 0.2 — 9.6 Other services 1.7 0.1 0.2 0.2 — 2.2 Midstream services 64.0 42.5 103.5 63.3 — 273.3 NGL services—related parties — — — 1.0 (1.0) — Midstream services—related parties — — — 1.0 (1.0) — Revenue from contracts with customers 721.1 827.9 263.1 165.1 (425.3) 1,551.9 Realized gain (loss) on derivatives 2.4 (7.3) (1.0) 1.1 — (4.8) Change in fair value of derivatives (1.3) 5.6 0.8 (1.1) — 4.0 Total revenues 722.2 826.2 262.9 165.1 (425.3) 1,551.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (552.6) (710.8) (135.5) (89.0) 425.3 (1,062.6) Operating expenses (76.5) (31.1) (23.9) (23.7) — (155.2) Segment profit $ 93.1 $ 84.3 $ 103.5 $ 52.4 $ — $ 333.3 Capital expenditures $ 31.6 $ 21.3 $ 25.0 $ 7.1 $ 1.2 $ 86.2 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) Operating expenses (53.1) (32.0) (27.0) (24.7) — (136.8) Segment profit $ 91.8 $ 104.5 $ 110.7 $ 67.3 $ — $ 374.3 Capital expenditures $ 51.6 $ 17.7 $ 22.1 $ 11.8 $ 1.5 $ 104.7 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2024 Natural gas sales $ 119.5 $ 230.5 $ 52.7 $ 56.3 $ — $ 459.0 NGL sales (12.8) 1,433.6 (1.6) (8.4) — 1,410.8 Crude oil and condensate sales 747.0 — 65.6 — — 812.6 Other — — — 1.2 — 1.2 Product sales 853.7 1,664.1 116.7 49.1 — 2,683.6 Natural gas sales—related parties — 0.1 — — (0.1) — NGL sales—related parties 495.2 18.5 214.3 139.1 (867.1) — Crude oil and condensate sales—related parties — — — 6.9 (6.9) — Product sales—related parties 495.2 18.6 214.3 146.0 (874.1) — Gathering and transportation 81.3 52.3 120.5 86.6 — 340.7 Processing 31.5 1.2 69.0 49.5 — 151.2 NGL services — 31.2 — 0.1 — 31.3 Crude services 10.0 0.1 6.9 0.4 — 17.4 Other services 3.6 0.2 0.3 0.5 — 4.6 Midstream services 126.4 85.0 196.7 137.1 — 545.2 NGL services—related parties — — — 1.5 (1.5) — Midstream services—related parties — — — 1.5 (1.5) — Revenue from contracts with customers 1,475.3 1,767.7 527.7 333.7 (875.6) 3,228.8 Realized loss on derivatives (4.4) (0.9) (2.0) (0.4) — (7.7) Change in fair value of derivatives (3.7) (13.9) (3.3) (1.2) — (22.1) Total revenues 1,467.2 1,752.9 522.4 332.1 (875.6) 3,199.0 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,134.7) (1,500.3) (283.3) (170.3) 875.6 (2,213.0) Operating expenses (150.4) (57.9) (49.9) (49.6) — (307.8) Segment profit $ 182.1 $ 194.7 $ 189.2 $ 112.2 $ — $ 678.2 Capital expenditures $ 80.2 $ 52.9 $ 36.8 $ 17.6 $ 2.1 $ 189.6 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) Operating expenses (101.2) (65.6) (51.7) (50.7) — (269.2) Segment profit $ 187.8 $ 200.9 $ 205.4 $ 143.4 $ — $ 737.5 Capital expenditures $ 108.3 $ 30.0 $ 47.8 $ 29.9 $ 2.8 $ 218.8 The following table reconciles segment profit to income before non-controlling interest and income taxes in the consolidated statements of operations: Three Months Ended Six Months Ended 2024 2023 2024 2023 Segment profit $ 333.3 $ 374.3 $ 678.2 $ 737.5 Depreciation and amortization (162.6) (165.3) (327.9) (325.7) Impairments — — (14.2) — Gain (loss) on disposition of assets (0.9) 0.8 0.8 1.2 General and administrative (30.2) (27.9) (85.4) (57.4) Interest expense, net of interest income (66.7) (68.8) (132.1) (137.3) Income (loss) from unconsolidated affiliate investments 0.3 (4.6) (0.5) (4.7) Other income 3.8 0.4 4.3 0.4 Income before non-controlling interest and income taxes $ 77.0 $ 108.9 $ 123.2 $ 214.0 The table below represents information about segment assets as of June 30, 2024 and December 31, 2023 (in millions): Segment Identifiable Assets: June 30, 2024 December 31, 2023 Permian $ 2,813.0 $ 2,813.6 Louisiana 2,000.9 2,031.8 Oklahoma 2,177.8 2,275.8 North Texas 943.7 1,017.7 Corporate (1) 216.9 189.7 Total identifiable assets $ 8,152.3 $ 8,328.6 ____________________________ (1)

Other Information

Other Information	6 Months Ended
	Jun. 30, 2024
Other Liabilities Disclosure [Abstract]
Other Information	(12) 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, 2024 December 31, 2023 Product inventory $ 73.3 $ 46.4 Prepaid expenses and other 29.4 19.0 Other current assets $ 102.7 $ 65.4 Other current liabilities: June 30, 2024 December 31, 2023 Accrued interest $ 62.9 $ 63.4 Accrued wages and benefits, including taxes 15.3 23.2 Accrued ad valorem taxes 23.3 33.3 Capital expenditure accruals 41.0 64.6 Short-term lease liability 36.6 28.2 Operating expense accruals 19.7 21.5 Accrued common unit repurchase 22.9 41.5 Other 27.6 2.8 Other current liabilities $ 249.3 $ 278.5

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(13) 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 natural gas during the storm, including one that resulted in litigation. The litigation was between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC in the 162nd District Court in Dallas County, Texas. In April 2024, we settled this matter and all claims related to this dispute have been dismissed. 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 approximately 90 natural gas producers, pipelines, marketers, sellers, and traders, including EnLink Gas. The plaintiffs asserted claims of tortious interference, nuisance, and unjust enrichment against all defendants and are seeking economic and punitive damages and disgorgement of profits. EnLink Gas believes it has substantial defenses to these claims and intends to vigorously dispute these allegations and 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, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Pay vs Performance Disclosure
Net Income (Loss) Attributable to Parent	$ 38.1	$ 54.3	$ 52.6	$ 112.5

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Jun. 30, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation
Revenue Recognition	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. 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.
Property and Equipment	Property and Equipment In accordance with ASC 360 , Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances, or triggering events, indicate that their carrying value may not be recoverable. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.
Non-controlling Interests	Non-controlling Interests Our non-controlling interests are comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50.0% share of the Ascension JV. Certain of our joint venture arrangements provide us or our joint venture partners with the right, under certain circumstances, to cause a purchase or sale of interest in the joint venture or to seek to sell the entire joint venture. At any time after June 30, 2025, NGP has the right to arrange a sale of the Delaware Basin JV for the best available price; provided that, if NGP exercises this right, we are permitted, but not required, to purchase NGP’s interest at a certain call price.
Recent Accounting Pronouncements	Recent Accounting Pronouncements On November 27, 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” (“ASU 2023-07”). ASU 2023-07 amends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The impact of ASU 2023-07 would be limited to the disclosures within the footnotes of the consolidated financial statements. On December 14, 2023, the FASB issued ASU No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” (“ASU 2023-09”). ASU 2023-09 is intended to improve the transparency of income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. ASU 2023-09 will become effective for annual periods beginning after December 15, 2024, with early adoption permitted. Management is currently evaluating ASU 2023-09 to determine its impact on the Company’s annual disclosures.

Significant Accounting Polices

Significant Accounting Polices (Tables)	6 Months Ended
	Jun. 30, 2024
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. 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 (1) 2024 (remaining) $ 85.3 2025 157.1 2026 159.3 2027 130.9 2028 127.1 Thereafter 1,133.5 Total $ 1,793.2 ____________________________ (1) The contractually committed fees include $19.8 million in 2025, $33.8 million in 2026, $33.7 million in 2027, $33.8 million in 2028, and $722.9 million from 2029 through 2050 for MVCs under our transportation services agreement with a subsidiary of ExxonMobil. We may not realize the full value of these fees or realize them in different periods under any financial arrangement entered into in respect of the Pecan Island transportation agreement. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Other Recent Developments” for additional information.

Intangible Assets (Tables)

Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2024
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, 2024 Customer relationships, beginning of period $ 1,844.8 $ (1,051.2) $ 793.6 Amortization expense — (63.7) (63.7) Customer relationships, end of period $ 1,844.8 $ (1,114.9) $ 729.9
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2024 (remaining) $ 63.9 2025 110.2 2026 106.3 2027 106.3 2028 106.3 Thereafter 236.9 Total $ 729.9

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2024
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	We recorded the following amounts (in millions) on our consolidated balance sheets related to our transactions with the Cedar Cove JV: June 30, 2024 December 31, 2023 Accrued natural gas, NGLs, condensate, and crude oil purchases $ 0.3 $ 0.3 We recorded the following amounts (in millions) on our consolidated statements of operations related to our transactions with the Cedar Cove JV: Three Months Ended Six Months Ended 2024 2023 2024 2023 Midstream services revenue $ 0.5 $ 0.6 $ 1.0 $ 1.3 Cost of sales, exclusive of operating expenses and depreciation and amortization (1.4) (2.5) (2.8) (4.0)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2024
Debt Disclosure [Abstract]
Summary of Debt	As of June 30, 2024 and December 31, 2023, long-term debt consisted of the following (in millions): June 30, 2024 December 31, 2023 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ 229.0 $ — $ 229.0 $ — $ — $ — AR Facility due 2025 (2) 254.4 — 254.4 300.0 — 300.0 ENLK’s 4.40% Senior unsecured notes due 2024 — — — 97.9 — 97.9 ENLK’s 4.15% Senior unsecured notes due 2025 421.6 — 421.6 421.6 — 421.6 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.1) 490.9 491.0 (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 (2.5) 997.5 1,000.0 (2.7) 997.3 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 (4.9) 445.1 450.0 (5.0) 445.0 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 $ 4,694.7 $ (7.8) 4,686.9 $ 4,609.2 $ (8.2) 4,601.0 Debt issuance cost (3) (29.5) (32.1) Less: Current maturities of long-term debt (4)(5) (421.2) (97.9) Long-term debt, net of unamortized issuance cost $ 4,236.2 $ 4,471.0 ____________________________ (1) The effective interest rate was 6.9% at June 30, 2024. (2) The effective interest rate was 6.3% and 6.4% at June 30, 2024 and December 31, 2023, respectively. (3) Net of accumulated amortization of $22.6 million and $20.0 million at June 30, 2024 and December 31, 2023, respectively. (4) The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes are classified as “Current maturities of long-term debt” in the consolidated balance sheet as of December 31, 2023 as these notes matured on April 1, 2024. (5) The outstanding balance, net of debt issuance costs, of ENLK’s 4.15% senior unsecured notes are classified as “Current maturities of long-term debt” in the consolidated balance sheet as of June 30, 2024 as these notes mature on June 1, 2025.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax expense are as follows (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Current income tax expense $ (0.2) $ (0.2) $ (0.4) $ (0.3) Deferred income tax expense (9.8) (18.8) (5.8) (29.6) Income tax expense $ (10.0) $ (19.0) $ (6.2) $ (29.9)
Reconciliation of Total Income Tax Expense to Income before Income Taxes	The following schedule reconciles income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Expected income tax expense based on federal statutory tax rate $ (8.3) $ (15.4) $ (10.5) $ (29.9) State income tax expense, net of federal benefit (1.1) (2.0) (1.5) (3.8) Unit-based compensation (1) 0.4 0.1 7.7 6.6 Other (1.0) (1.7) (1.9) (2.8) Income tax expense $ (10.0) $ (19.0) $ (6.2) $ (29.9) ____________________________ (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, 2024
Partners' Capital [Abstract]
Schedule of Preferred Units Exchange Activity	A summary of the exchange activity by the holders of the Series B Preferred Units during the three months ended June 30, 2024 is provided below (in millions, except per unit amounts): Series B Preferred Units Canceled Series B Preferred Units Exchanged ENLC Common Units Issued Loss on Exchange of Series B Preferred Units Transaction date Units Units $ Units $ $ April 2024 2,604,046 2,608,696 (1) $ 38.3 3,000,000 $ 41.2 $ (2.9) May 2024 3,478,262 3,478,262 $ 51.6 4,000,000 $ 53.9 $ (2.3) ____________________________ (1) Includes 4,650 accrued and unpaid Series B Preferred Units that holders were entitled to receive in a PIK Distribution in respect of the first quarter of 2024 as of the date of the exchange of such Series B Preferred Units.
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2024 and 2023 is provided below: Declaration period PIK Distribution Cash distribution (in millions) Date paid/payable 2024 Fourth Quarter of 2023 136,439 $ 15.3 February 9, 2024 First Quarter of 2024 130,270 $ 14.7 May 14, 2024 Second Quarter of 2024 (1) — $ 12.8 August 14, 2024 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 ____________________________ (1) On September 8, 2023, we amended and restated the limited partnership agreement of ENLK (the “ENLK LPA”) to terminate the rights of the holders of the Series B Preferred Units to receive PIK distributions beginning with the quarter ending June 30, 2024, and in connection with such termination of PIK distributions, increase the cash distribution per Series B Preferred Unit from $0.28125 to $0.31875, in addition to the continued payment of the Series B Excess Cash Payment Amount (as defined in the ENLK LPA). 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 is provided below: Declaration period (1) Distribution rate (2) Cash distribution (in millions) Date paid/payable 2024 December 15, 2023 – March 14, 2024 9.749 % $ 9.0 March 15, 2024 March 15, 2024 – June 14, 2024 9.701 % $ 9.1 June 17, 2024 June 15, 2024 – September 14, 2024 9.716 % $ 9.0 September 16, 2024 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 ____________________________ (1) Distributions on the Series C Preferred Units accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. (2) 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%. Starting on September 15, 2023, distributions on the Series C Preferred Units are based on the 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, 2024
Earnings Per Share [Abstract]
Summary of Repurchase Agreements	The table below provides a summary of the Board’s authorizations of the 2023 and 2024 common unit repurchase programs. Date Board Action Authorized Amount December 2022 Reauthorization of common unit repurchase program and set amount available for repurchases for 2023 $ 200 November 2023 Increase in 2023 common unit repurchase program $ 50 December 2023 Reauthorization of common unit repurchase program and set amount available for repurchases for 2024 $ 200 July 2024 Increase in 2024 common unit repurchase program $ 50 ____________________________ (1) The authorized amount includes repurchases of common units held by GIP. Refer to “Note 4—Related Party Transactions” for more information on our ENLC common unit repurchase agreement with GIP. 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 2024 2023 2024 2023 Publicly held ENLC common units 2,035,157 3,230,504 4,201,962 5,437,809 ENLC common units held by GIP (1) 1,862,695 1,910,877 5,143,332 4,147,987 Total ENLC common units 3,897,852 5,141,381 9,345,294 9,585,796 Aggregate cost for publicly held ENLC common units $ 27.1 $ 32.2 $ 54.0 $ 59.0 Aggregate cost for ENLC common units held by GIP 23.1 23.2 64.6 47.8 Excise tax on common unit repurchases (0.2) 0.7 — 0.7 Total aggregate cost for ENLC common units $ 50.0 $ 56.1 $ 118.6 $ 107.5 Average price paid per publicly held ENLC common unit (2) $ 13.32 $ 9.96 $ 12.85 $ 10.85 Average price paid per ENLC common unit held by GIP (2)(3) $ 12.40 $ 12.12 $ 12.56 $ 11.53 ____________________________ (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 2024 2023 2024 2023 Distributed earnings allocated to: Common units (1) $ 59.8 $ 57.8 $ 119.6 $ 116.4 Unvested unit-based awards (1) 0.8 1.0 1.5 1.9 Total distributed earnings $ 60.6 $ 58.8 $ 121.1 $ 118.3 Distribution in excess of earnings: Common units $ (27.4) $ (4.4) $ (72.8) $ (5.7) Unvested unit-based awards (0.3) (0.1) (0.9) (0.1) Total distribution in excess of earnings $ (27.7) $ (4.5) $ (73.7) $ (5.8) Net income attributable to ENLC allocated to: Common units (2) $ 32.4 $ 53.4 $ 46.8 $ 110.7 Unvested unit-based awards (2) 0.5 0.9 0.6 1.8 Total net income attributable to ENLC (2) $ 32.9 $ 54.3 $ 47.4 $ 112.5 Net income attributable to ENLC per unit: Basic (2) $ 0.07 $ 0.12 $ 0.11 $ 0.24 Diluted (2) $ 0.07 $ 0.12 $ 0.10 $ 0.24 ____________________________ (1) Represents distribution activity consistent with the distribution activity table below. (2) Includes the loss on exchange of Series B Preferred Units. 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 2024 2023 2024 2023 Basic weighted average units outstanding: Weighted average common units outstanding 451.4 462.7 451.3 465.8 Diluted weighted average units outstanding: Weighted average basic common units outstanding 451.4 462.7 451.3 465.8 Dilutive effect of unvested restricted units 2.7 4.0 2.7 4.1 Total weighted average diluted common units outstanding 454.1 466.7 454.0 469.9
Summary of Distribution Activity	A summary of our distribution activity related to the ENLC common units for the six months ended June 30, 2024 and 2023, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2024 Fourth Quarter of 2023 $ 0.1325 February 9, 2024 First Quarter of 2024 $ 0.1325 May 14, 2024 Second Quarter of 2024 $ 0.1325 August 14, 2024 2023 Fourth Quarter of 2022 $ 0.1250 February 13, 2023 First Quarter of 2023 $ 0.1250 May 12, 2023 Second Quarter of 2023 $ 0.1250 August 11, 2023

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2024
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 swap are as follows (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Change in fair value of interest rate swap $ 0.3 $ 7.5 $ 4.2 $ 5.9 Tax expense (0.2) (1.8) (1.1) (1.4) Unrealized gain on designated cash flow hedge $ 0.1 $ 5.7 $ 3.1 $ 4.5 Interest income is recognized from accumulated other comprehensive income from the monthly settlement of our interest rate swap and was included in our consolidated statements of operations as follows (in millions): Three Months Ended Six Months Ended 2024 2023 2024 2023 Interest income $ 1.5 $ 1.1 $ 3.0 $ 1.6 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 2024 2023 2024 2023 Change in fair value of derivatives $ 4.0 $ 5.3 $ (22.1) $ 3.9 Realized gain (loss) on derivatives (4.8) 6.0 (7.7) 19.3 Gain (loss) on derivative activity $ (0.8) $ 11.3 $ (29.8) $ 23.2
Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps	The fair value of derivative assets and liabilities related to the interest rate swap are as follows (in millions): June 30, 2024 December 31, 2023 Fair value of derivative assets—current $ 4.4 $ 3.3 Fair value of derivative assets—long-term 0.7 — Fair value of derivative liabilities—long-term — (2.4) Net fair value of interest rate swap $ 5.1 $ 0.9 The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): June 30, 2024 December 31, 2023 Fair value of derivative assets—current $ 58.1 $ 73.6 Fair value of derivative assets—long-term 10.6 27.0 Fair value of derivative liabilities—current (64.1) (62.7) Fair value of derivative liabilities—long-term (13.1) (24.3) Net fair value of commodity derivatives $ (8.5) $ 13.6
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, 2024 (in millions, except volumes). The remaining term of the contracts extend no later than January 2029. Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps MMgals (126.4) $ (13.9) NGL (long contracts) Swaps MMgals 63.6 (0.1) Natural gas (short contracts) Swaps and futures Bbtu (116.7) 50.7 Natural gas (long contracts) Swaps and futures Bbtu 105.5 (45.7) Crude and condensate (short contracts) Swaps and futures MMbbls (6.6) (5.6) Crude and condensate (long contracts) Swaps and futures MMbbls 1.3 6.1 Total fair value of commodity derivatives $ (8.5)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2024
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, 2024 December 31, 2023 Interest rate swap (1) $ 5.1 $ 0.9 Commodity derivatives (2) $ (8.5) $ 13.6 ____________________________ (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. Long-term debt, including current maturities of long-term debt. The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions): June 30, 2024 December 31, 2023 Carrying Value Fair Carrying Value Fair Long-term debt, including current maturities of long-term debt (1) $ 4,657.4 $ 4,495.9 $ 4,568.9 $ 4,427.0 ____________________________ (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 $29.5 million and $32.1 million as of June 30, 2024 and December 31, 2023, respectively. The respective fair values do not factor in debt issuance costs. The fair values of all senior unsecured notes as of June 30, 2024 and December 31, 2023 were based on Level 2 inputs from third-party market quotations.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2024
Segment Reporting [Abstract]
Summary of Financial Information	We evaluate the performance of our operating segments based on segment profit. 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, 2024 Natural gas sales $ 15.3 $ 110.9 $ 19.9 $ 31.4 $ — $ 177.5 NGL sales (6.2) 665.5 (0.6) (3.6) — 655.1 Crude oil and condensate sales 410.4 — 34.7 — — 445.1 Other — — — 0.9 — 0.9 Product sales 419.5 776.4 54.0 28.7 — 1,278.6 NGL sales—related parties 237.6 9.0 105.6 68.5 (420.7) — Crude oil and condensate sales—related parties — — — 3.6 (3.6) — Product sales—related parties 237.6 9.0 105.6 72.1 (424.3) — Gathering and transportation 41.6 27.9 64.7 41.0 — 175.2 Processing 14.5 0.6 35.4 21.9 — 72.4 NGL services — 13.9 — — — 13.9 Crude services 6.2 — 3.2 0.2 — 9.6 Other services 1.7 0.1 0.2 0.2 — 2.2 Midstream services 64.0 42.5 103.5 63.3 — 273.3 NGL services—related parties — — — 1.0 (1.0) — Midstream services—related parties — — — 1.0 (1.0) — Revenue from contracts with customers 721.1 827.9 263.1 165.1 (425.3) 1,551.9 Realized gain (loss) on derivatives 2.4 (7.3) (1.0) 1.1 — (4.8) Change in fair value of derivatives (1.3) 5.6 0.8 (1.1) — 4.0 Total revenues 722.2 826.2 262.9 165.1 (425.3) 1,551.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (552.6) (710.8) (135.5) (89.0) 425.3 (1,062.6) Operating expenses (76.5) (31.1) (23.9) (23.7) — (155.2) Segment profit $ 93.1 $ 84.3 $ 103.5 $ 52.4 $ — $ 333.3 Capital expenditures $ 31.6 $ 21.3 $ 25.0 $ 7.1 $ 1.2 $ 86.2 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) Operating expenses (53.1) (32.0) (27.0) (24.7) — (136.8) Segment profit $ 91.8 $ 104.5 $ 110.7 $ 67.3 $ — $ 374.3 Capital expenditures $ 51.6 $ 17.7 $ 22.1 $ 11.8 $ 1.5 $ 104.7 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2024 Natural gas sales $ 119.5 $ 230.5 $ 52.7 $ 56.3 $ — $ 459.0 NGL sales (12.8) 1,433.6 (1.6) (8.4) — 1,410.8 Crude oil and condensate sales 747.0 — 65.6 — — 812.6 Other — — — 1.2 — 1.2 Product sales 853.7 1,664.1 116.7 49.1 — 2,683.6 Natural gas sales—related parties — 0.1 — — (0.1) — NGL sales—related parties 495.2 18.5 214.3 139.1 (867.1) — Crude oil and condensate sales—related parties — — — 6.9 (6.9) — Product sales—related parties 495.2 18.6 214.3 146.0 (874.1) — Gathering and transportation 81.3 52.3 120.5 86.6 — 340.7 Processing 31.5 1.2 69.0 49.5 — 151.2 NGL services — 31.2 — 0.1 — 31.3 Crude services 10.0 0.1 6.9 0.4 — 17.4 Other services 3.6 0.2 0.3 0.5 — 4.6 Midstream services 126.4 85.0 196.7 137.1 — 545.2 NGL services—related parties — — — 1.5 (1.5) — Midstream services—related parties — — — 1.5 (1.5) — Revenue from contracts with customers 1,475.3 1,767.7 527.7 333.7 (875.6) 3,228.8 Realized loss on derivatives (4.4) (0.9) (2.0) (0.4) — (7.7) Change in fair value of derivatives (3.7) (13.9) (3.3) (1.2) — (22.1) Total revenues 1,467.2 1,752.9 522.4 332.1 (875.6) 3,199.0 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,134.7) (1,500.3) (283.3) (170.3) 875.6 (2,213.0) Operating expenses (150.4) (57.9) (49.9) (49.6) — (307.8) Segment profit $ 182.1 $ 194.7 $ 189.2 $ 112.2 $ — $ 678.2 Capital expenditures $ 80.2 $ 52.9 $ 36.8 $ 17.6 $ 2.1 $ 189.6 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) Operating expenses (101.2) (65.6) (51.7) (50.7) — (269.2) Segment profit $ 187.8 $ 200.9 $ 205.4 $ 143.4 $ — $ 737.5 Capital expenditures $ 108.3 $ 30.0 $ 47.8 $ 29.9 $ 2.8 $ 218.8 The following table reconciles segment profit to income before non-controlling interest and income taxes in the consolidated statements of operations: Three Months Ended Six Months Ended 2024 2023 2024 2023 Segment profit $ 333.3 $ 374.3 $ 678.2 $ 737.5 Depreciation and amortization (162.6) (165.3) (327.9) (325.7) Impairments — — (14.2) — Gain (loss) on disposition of assets (0.9) 0.8 0.8 1.2 General and administrative (30.2) (27.9) (85.4) (57.4) Interest expense, net of interest income (66.7) (68.8) (132.1) (137.3) Income (loss) from unconsolidated affiliate investments 0.3 (4.6) (0.5) (4.7) Other income 3.8 0.4 4.3 0.4 Income before non-controlling interest and income taxes $ 77.0 $ 108.9 $ 123.2 $ 214.0
Schedule of Segment Assets	The table below represents information about segment assets as of June 30, 2024 and December 31, 2023 (in millions): Segment Identifiable Assets: June 30, 2024 December 31, 2023 Permian $ 2,813.0 $ 2,813.6 Louisiana 2,000.9 2,031.8 Oklahoma 2,177.8 2,275.8 North Texas 943.7 1,017.7 Corporate (1) 216.9 189.7 Total identifiable assets $ 8,152.3 $ 8,328.6 ____________________________ (1)

Other Information (Tables)

Other Information (Tables)	6 Months Ended
	Jun. 30, 2024
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, 2024 December 31, 2023 Product inventory $ 73.3 $ 46.4 Prepaid expenses and other 29.4 19.0 Other current assets $ 102.7 $ 65.4 Other current liabilities: June 30, 2024 December 31, 2023 Accrued interest $ 62.9 $ 63.4 Accrued wages and benefits, including taxes 15.3 23.2 Accrued ad valorem taxes 23.3 33.3 Capital expenditure accruals 41.0 64.6 Short-term lease liability 36.6 28.2 Operating expense accruals 19.7 21.5 Accrued common unit repurchase 22.9 41.5 Other 27.6 2.8 Other current liabilities $ 249.3 $ 278.5

General (Details)

General (Details)	6 Months Ended
	Jun. 30, 2024 Bcf / d processingPlant fractionator mi bbl
Related Party Transaction [Line Items]
Number of miles of pipeline | mi	13,600
Number of natural gas processing plants | processingPlant	25
Amount of processing capacity | Bcf / d	5.9
Number of fractionators | fractionator	7
Capacity of fractionators per day, barrels | bbl	316,300
ENLC | GIP Stetson II
Related Party Transaction [Line Items]
Membership interest in the General Partner as a percent	45%

Significant Accounting Polici_3

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Jun. 30, 2024 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,793.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 85.3
Revenue, remaining performance obligation, expected timing of satisfaction, period	6 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 157.1
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Related Party
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 19.8
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 159.3
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Related Party
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 33.8
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 130.9
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Related Party
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 33.7
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 127.1
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Related Party
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 33.8
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,133.5
Revenue, remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Related Party
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 722.9
Revenue, remaining performance obligation, expected timing of satisfaction, period

Significant Accounting Polici_4

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2024	Mar. 31, 2024	Jun. 30, 2023	Jun. 30, 2023
Noncontrolling Interest [Line Items]
Impairment charges	$ 0	$ 14.2	$ 0	$ 0
Delaware Basin JV
Noncontrolling Interest [Line Items]
Ownership interest	49.90%
Ascension JV
Noncontrolling Interest [Line Items]
Ownership interest	50%

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 31.9	$ 31.9	$ 63.7	$ 63.8
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]
Intangible asset, weighted average remaining amortization period	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, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Finite-lived Intangible Assets [Roll Forward]
Gross carrying amount, beginning balance			$ 1,844.8
Accumulated amortization, beginning balance			(1,051.2)
Net carrying amount, beginning balance			793.6
Amortization expense	$ (31.9)	$ (31.9)	(63.7)	$ (63.8)
Gross carrying amount, ending balance	1,844.8		1,844.8
Accumulated amortization, ending balance	(1,114.9)		(1,114.9)
Net carrying amount, ending balance	$ 729.9		$ 729.9

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
2024	$ 63.9
2025	110.2
2026	106.3
2027	106.3
2028	106.3
Thereafter	236.9
Total	$ 729.9	$ 793.6

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
	Jan. 16, 2024	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Related Party Transaction [Line Items]
Accrued natural gas, NGLs, condensate, and crude oil purchases		$ 86.9		$ 86.9		$ 126.5
Midstream services revenue		1,551.9	$ 1,518.8	3,228.8	$ 3,274.4
Cost of sales, exclusive of operating expenses and depreciation and amortization		(1,062.6)	(1,019)	(2,213)	(2,290.9)
Repurchase agreement renewal term	1 year
Midstream services revenue
Related Party Transaction [Line Items]
Midstream services revenue		273.3	279.5	545.2	558.8
Product sales—related parties | Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Accrued natural gas, NGLs, condensate, and crude oil purchases		0.3		0.3		$ 0.3
Cost of sales, exclusive of operating expenses and depreciation and amortization		(1.4)	(2.5)	(2.8)	(4)
Product sales—related parties | Midstream services revenue | Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Midstream services revenue		$ 0.5	$ 0.6	$ 1	$ 1.3

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Debt Instrument
Outstanding Principal	$ 4,694.7	$ 4,609.2
Premium (Discount)	(7.8)	(8.2)
Long-Term Debt	4,686.9	4,601
Debt issuance costs	(29.5)	(32.1)
Less: Current maturities of long-term debt	(421.2)	(97.9)
Long-term debt, net of unamortized issuance cost	4,236.2	4,471
Debt issuance cost accumulated amortization	22.6	20
Revolving Credit Facility Due 2027
Debt Instrument
Outstanding Principal	229	0
Premium (Discount)	0	0
Long-Term Debt	$ 229	0
Effective interest rate (as a percent)	6.90%
AR Facility due 2025
Debt Instrument
Outstanding Principal	$ 254.4	300
Premium (Discount)	0	0
Long-Term Debt	$ 254.4	$ 300
Effective interest rate (as a percent)	6.30%	6.40%
4.40% Senior Notes due 2024
Debt Instrument
Outstanding Principal	$ 0	$ 97.9
Premium (Discount)	0	0
Long-Term Debt	$ 0	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
Long-Term Debt	$ 421.6	421.6
Stated interest rate (as a percent)	4.15%
4.85% Senior Unsecured Notes Due 2026
Debt Instrument
Outstanding Principal	$ 491	491
Premium (Discount)	(0.1)	(0.2)
Long-Term Debt	$ 490.9	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	1,000
Premium (Discount)	(2.5)	(2.7)
Long-Term Debt	$ 997.5	997.3
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)	(4.9)	(5)
Long-Term Debt	$ 445.1	445
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) $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($)
Debt Instrument
Increase (decrease) in accounts receivable	$ 600.6
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity	345.5
Accounts receivable securitization facility, outstanding amount	254.4
Letters of credit
Debt Instrument
Additional amount available (not to exceed)	1,400
Line of credit facility, fair value of amount outstanding	229
Letters of credit | Letter of Credit
Debt Instrument
Maximum borrowing capacity	500
Letters of credit | Letter of Credit | ENLC
Debt Instrument
Line of credit facility, fair value of amount outstanding	$ 14.6

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, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.2)	$ (0.2)	$ (0.4)	$ (0.3)
Deferred income tax expense	(9.8)	(18.8)	(5.8)	(29.6)
Income tax expense	(10)	(19)	(6.2)	(29.9)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax expense based on federal statutory tax rate	(8.3)	(15.4)	(10.5)	(29.9)
State income tax expense, net of federal benefit	(1.1)	(2)	(1.5)	(3.8)
Unit-based compensation	0.4	0.1	7.7	6.6
Other	(1)	(1.7)	(1.9)	(2.8)
Income tax expense	$ (10)	$ (19)	$ (6.2)	$ (29.9)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 784.9	$ 758.3
Deferred tax assets, valuation allowance	1.2	1.2
Deferred tax liabilities	895.9	862.5
Net deferred tax liabilities	$ 111	$ 104.2

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended			6 Months Ended
	Aug. 05, 2024	Jul. 31, 2024	May 31, 2024	Apr. 30, 2024	Jun. 30, 2024	Aug. 07, 2024	Dec. 31, 2023
Partnership agreement
Common units conversion ratio					1.15
Series B Preferred Stock
Partnership agreement
Series B preferred units exchanged (in shares)			3,478,262	2,608,696
Exchange of Series B Preferred Units (in shares)			4,000,000	3,000,000
Conversion price (in dollars per share)					$ 0.15
Initial non-refundable fee			$ 3.5
Series B Preferred Stock | Subsequent Event
Partnership agreement
Series B preferred units exchanged (in shares)		8,695,654
Exchange of Series B Preferred Units (in shares)		10,000,000
Stock redeemed during period (in shares)	12,698,414
Total consideration paid	$ 200.2
Preferred stock outstanding (in shares)						27,365,971
Series B Preferred Stock | Limited Partner
Partnership agreement
Partners' capital, conversion obligation period of consecutive trading days					30 days
Partners' capital, average trading price, number of trading days					2 days
Percentage of issue price					150%
Preferred stock (in dollars per share)					$ 15
Series B Preferred Stock | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, outstanding (in shares)					48,760,039		54,575,638
Preferred units, issued (in shares)					48,760,039		54,575,638
Price payable, overage (in dollars per unit)					$ 7.32
Repurchase of Series C Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, outstanding (in shares)					366,500
Preferred units, issued (in shares)					366,500		366,500

Certain Provisions of the ENL_4

Certain Provisions of the ENLK Partnership Agreement - Preferred Units Exchange Activity (Details) - USD ($) $ in Millions	1 Months Ended			3 Months Ended
	Jul. 31, 2024	May 31, 2024	Apr. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022
Series B Preferred Stock | Limited Partner
Partnership agreement
Distribution paid-in kind (in shares)			4,650	0	130,270	136,439	135,759	135,421	0
Series B Preferred Stock
Partnership agreement
Series B preferred units canceled (in shares)		3,478,262	2,604,046
Series B preferred units exchanged (in shares)		3,478,262	2,608,696
Series B Preferred Units Exchanged		$ 51.6	$ 38.3
ENLC common units issued (in shares)		4,000,000	3,000,000
ENLC Common Units Issued		$ 53.9	$ 41.2
Loss on Exchange of Series B Preferred Units		$ (2.3)	$ (2.9)
Series B Preferred Stock | Subsequent Event
Partnership agreement
Series B preferred units exchanged (in shares)	8,695,654
ENLC common units issued (in shares)	10,000,000

Certain Provisions of the ENL_5

Certain Provisions of the ENLK Partnership Agreement - Summary of Distribution (Details) - USD ($) $ / shares in Units, $ in Millions				1 Months Ended	3 Months Ended
	Sep. 15, 2023	Sep. 08, 2023	Dec. 15, 2022	Apr. 30, 2024	Sep. 14, 2024	Jun. 30, 2024	Jun. 14, 2024	Mar. 31, 2024	Mar. 14, 2024	Dec. 31, 2023	Sep. 14, 2023	Jun. 30, 2023	Jun. 14, 2023	Mar. 31, 2023	Mar. 14, 2023	Dec. 31, 2022
Series B Preferred Stock | EnLink Midstream Partners, LP
Partnership agreement
Annual rate on issue price payable in cash		28.125%				31.875%
Series B Preferred Stock | Limited Partner
Partnership agreement
Distribution paid-in kind (in shares)				4,650		0		130,270		136,439		135,759		135,421		0
Cash distributions						$ 12.8		$ 14.7		$ 15.3		$ 15.3		$ 15.2		$ 17.3
Repurchase of Series C Preferred Units
Partnership agreement
Cash distributions							$ 9.1		$ 9		$ 9.3		$ 8.7		$ 8.4
Distribution rate per unit	0.26161%						9.701%		9.749%		9.618%		9.051%		8.846%
Redemption price (per unit)			$ 1,000
Variable floating rate percentage	4.11%		4.11%
Repurchase of Series C Preferred Units | Subsequent Event
Partnership agreement
Cash distributions					$ 9
Distribution rate per unit					9.716%

Members' Equity - Board_s Autho

Members' Equity - Board’s Authorizations of the Common Unit Repurchase Program (Details) - USD ($) $ in Millions	Jul. 31, 2024	Dec. 31, 2023	Nov. 30, 2023	Dec. 31, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Repurchase program, amount authorized		$ 200		$ 200
Stock repurchase program increase			$ 50
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Stock repurchase program increase	$ 50

Members' Equity - IP Repurchase

Members' Equity - IP Repurchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024		Jun. 30, 2023
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	3,897,852	5,141,381	9,345,294		9,585,796
Aggregate cost for common units	$ 50	$ 56.1	$ 77.1	[1]	$ 107.5
Excise tax on common unit repurchases	(0.2)	0.7	0		0.7
Total aggregate cost for ENLC common units	$ 50	$ 56.1	$ 118.6		$ 107.5
Public ENLC Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	2,035,157	3,230,504	4,201,962		5,437,809
Aggregate cost for common units	$ 27.1	$ 32.2	$ 54		$ 59
Average price of shares repurchased (in dollars per share)	$ 13.32	$ 9.96	$ 12.85		$ 10.85
ENCL Common Units Held by GIP
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	1,862,695	1,910,877	5,143,332		4,147,987
Aggregate cost for common units	$ 23.1	$ 23.2	$ 64.6		$ 47.8
Average price of shares repurchased (in dollars per share)	$ 12.40	$ 12.12	$ 12.56		$ 11.53
[1] Excludes the $41.5 million repurchase of ENLC common units held by GIP on February 19, 2024, which was accrued at December 31, 2023.

Members' Equity - Narrative (De

Members' Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		6 Months Ended
	Aug. 05, 2024	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024		Jun. 30, 2023
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)		3,897,852	5,141,381	9,345,294		9,585,796
Aggregate cost for common units		$ 50	$ 56.1	$ 77.1	[1]	$ 107.5
Accrued common unit repurchase		$ 22.9		$ 22.9
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	1,718,847
Aggregate cost for common units	$ 22.9
Average price of shares repurchased (in dollars per share)	$ 13.31
[1] Excludes the $41.5 million repurchase of ENLC common units held by GIP on February 19, 2024, which was accrued at December 31, 2023.

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, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Distributed earnings allocated to:
Total distributed earnings	$ 60.6	$ 58.8	$ 121.1	$ 118.3
Distribution in excess of earnings:
Total distribution in excess of earnings, basic	(27.7)	(4.5)	(73.7)	(5.8)
Total distribution in excess of earnings, diluted	(27.7)	(4.5)	(73.7)	(5.8)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, net of loss on exchange of Series B Preferred Units, basic	32.9	54.3	47.4	112.5
Total net income attributable to ENLC, net of loss on exchange of Series B Preferred Units, diluted	$ 32.9	$ 54.3	$ 47.4	$ 112.5
Net income attributable to ENLC per unit:
Basic (in dollars per share)	$ 0.07	$ 0.12	$ 0.11	$ 0.24
Diluted (in dollars per share)	$ 0.07	$ 0.12	$ 0.10	$ 0.24
Unvested unit-based awards
Distributed earnings allocated to:
Total distributed earnings	$ 0.8	$ 1	$ 1.5	$ 1.9
Distribution in excess of earnings:
Total distribution in excess of earnings, basic	(0.3)	(0.1)	(0.9)	(0.1)
Total distribution in excess of earnings, diluted	(0.3)	(0.1)	(0.9)	(0.1)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, net of loss on exchange of Series B Preferred Units, basic	0.5	0.9	0.6	1.8
Total net income attributable to ENLC, net of loss on exchange of Series B Preferred Units, diluted	0.5	0.9	0.6	1.8
Common units
Distributed earnings allocated to:
Total distributed earnings	59.8	57.8	119.6	116.4
Distribution in excess of earnings:
Total distribution in excess of earnings, basic	(27.4)	(4.4)	(72.8)	(5.7)
Total distribution in excess of earnings, diluted	(27.4)	(4.4)	(72.8)	(5.7)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, net of loss on exchange of Series B Preferred Units, basic	32.4	53.4	46.8	110.7
Total net income attributable to ENLC, net of loss on exchange of Series B Preferred Units, diluted	$ 32.4	$ 53.4	$ 46.8	$ 110.7

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, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in shares)	451.4	462.7	451.3	465.8
Dilutive effect of unvested restricted units (in shares)	2.7	4	2.7	4.1
Total weighted average diluted common units outstanding (in shares)	454.1	466.7	454	469.9

Members' Equity - Distributions

Members' Equity - Distributions (Details) - $ / shares	3 Months Ended
	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Distribution declared/unit (in dollars per share)	$ 0.1325	$ 0.1325	$ 0.1325	$ 0.1250	$ 0.1250	$ 0.1250

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) - USD ($)	Jun. 30, 2024	Jan. 31, 2023
Derivatives
Derivative, notional amount		$ 400,000,000
Derivative, fixed interest rate		3.8565%
Interest income out of accumulated other comprehensive loss over the next twelve months	$ 4,400,000
Commodity swaps
Derivatives
Maximum loss if counterparties fail to perform	68,700,000
Possible reduction in maximum loss if counterparties fail to perform	$ 2,700,000

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2024		Jun. 30, 2023		Jun. 30, 2024		Jun. 30, 2023		Dec. 31, 2023
Derivatives
Tax expense		$ (0.2)		$ (1.8)		$ (1.1)		$ (1.4)
Unrealized gain on designated cash flow hedge	[1]	0.1	[2]	5.7	[3]	3.1	[4]	4.5	[5]
Fair value of derivative assets—current		62.5				62.5				$ 76.9
Fair value of derivative assets—long-term		11.3				11.3				27
Fair value of derivative liabilities—current		(64.1)				(64.1)				(62.7)
Fair value of derivative liabilities—long-term		(13.1)				(13.1)				(26.7)
Interest income		1.5		1.1		3		1.6
Interest rate swap
Derivatives
Change in fair value of interest rate swap		0.3		7.5		4.2		5.9
Tax expense		(0.2)		(1.8)		(1.1)		(1.4)
Unrealized gain on designated cash flow hedge		0.1		$ 5.7		3.1		$ 4.5
Fair value of derivative assets—current		4.4				4.4				3.3
Fair value of derivative assets—long-term		0.7				0.7				0
Fair value of derivative liabilities—long-term		0				0				(2.4)
Net fair value of commodity derivatives		5.1				5.1				0.9
Commodity swaps
Derivatives
Fair value of derivative assets—current		58.1				58.1				73.6
Fair value of derivative assets—long-term		10.6				10.6				27
Fair value of derivative liabilities—current		(64.1)				(64.1)				(62.7)
Fair value of derivative liabilities—long-term		(13.1)				(13.1)				(24.3)
Net fair value of commodity derivatives		$ (8.5)				$ (8.5)				$ 13.6
[1] Includes tax expense of $0.2 million and $1.1 million for the three and six months ended June 30, 2024, respectively, and tax expense of $1.8 million and $1.4 million for the three and six months ended June 30, 2023, respectively. Includes tax expense of $0.2 million for the three months ended June 30, 2024. Includes tax expense of $1.8 million for the three months ended June 30, 2023. Includes tax expense of $1.1 million for the six months ended June 30, 2024. Includes tax expense of $1.4 million for the six months ended June 30, 2023.

Derivatives - Components of Com

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Derivatives
Change in fair value of interest rate swap	$ 4	$ 5.3	$ (22.1)	$ 3.9
Gain (loss) on derivative activity	(0.8)	11.3	(29.8)	23.2
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of interest rate swap	4	5.3	(22.1)	3.9
Realized gain (loss) on derivatives	(4.8)	6	(7.7)	19.3
Gain (loss) on derivative activity	$ (0.8)	$ 11.3	$ (29.8)	$ 23.2

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, 2024 USD ($) BTU gal bbl	Dec. 31, 2023 USD ($)
Derivatives
Net fair value of commodity derivatives	$ (8.5)	$ 13.6
NGL | Short
Derivatives
Notional amount (in MMgasl or MMBLS) | gal	126.4
Net fair value of commodity derivatives	$ (13.9)
NGL | Long
Derivatives
Notional amount (in MMgasl or MMBLS) | gal	63.6
Net fair value of commodity derivatives	$ (0.1)
Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | BTU	116.7
Net fair value of commodity derivatives	$ 50.7
Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | BTU	105.5
Net fair value of commodity derivatives	$ (45.7)
Crude and Condensate | Short
Derivatives
Notional amount (in MMgasl or MMBLS) | bbl	6.6
Net fair value of commodity derivatives	$ (5.6)
Crude and Condensate | Long
Derivatives
Notional amount (in MMgasl or MMBLS) | bbl	1.3
Net fair value of commodity derivatives	$ 6.1

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Interest rate swap
Fair Value
Net fair value of commodity derivatives	$ 5.1	$ 0.9
Commodity derivatives
Fair Value
Net fair value of commodity derivatives	(8.5)	13.6
Level 2 | Interest rate swap | Recurring
Fair Value
Net fair value of commodity derivatives	5.1	0.9
Level 2 | Commodity derivatives | Recurring
Fair Value
Net fair value of commodity derivatives	$ (8.5)	$ 13.6

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Fair Value
Debt issuance costs	$ 29.5	$ 32.1
Carrying Value
Fair Value
Long-term debt	4,657.4	4,568.9
Fair Value
Fair Value
Long-term debt	$ 4,495.9	$ 4,427

Segment Information - Narrative

Segment Information - Narrative (Details)	6 Months Ended
	Jun. 30, 2024 segment
Segment Reporting [Abstract]
Number of reportable segments	5

Segment Information - Summarize

Segment Information - Summarized Financial Information by Reportable Segment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Segment Reporting
Revenue from contracts with customers	$ 1,551.9	$ 1,518.8	$ 3,228.8	$ 3,274.4
Realized gain (loss) on derivatives	(4.8)	6	(7.7)	19.3
Change in fair value of derivatives	4	5.3	(22.1)	3.9
Total revenues	1,551.1	1,530.1	3,199	3,297.6
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,062.6)	(1,019)	(2,213)	(2,290.9)
Operating expenses	(155.2)	(136.8)	(307.8)	(269.2)
Segment profit	333.3	374.3	678.2	737.5
Capital expenditures	86.2	104.7	189.6	218.8
Permian
Segment Reporting
Revenue from contracts with customers	721.1	627.3	1,475.3	1,226.2
Realized gain (loss) on derivatives	2.4	5.4	(4.4)	1.4
Change in fair value of derivatives	(1.3)	(7.9)	(3.7)	(1.6)
Total revenues	722.2	624.8	1,467.2	1,226
Cost of sales, exclusive of operating expenses and depreciation and amortization	(552.6)	(479.9)	(1,134.7)	(937)
Operating expenses	(76.5)	(53.1)	(150.4)	(101.2)
Segment profit	93.1	91.8	182.1	187.8
Capital expenditures	31.6	51.6	80.2	108.3
Louisiana
Segment Reporting
Revenue from contracts with customers	827.9	841.1	1,767.7	1,946.8
Realized gain (loss) on derivatives	(7.3)	(7.8)	(0.9)	(0.6)
Change in fair value of derivatives	5.6	18.2	(13.9)	9.2
Total revenues	826.2	851.5	1,752.9	1,955.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(710.8)	(715)	(1,500.3)	(1,688.9)
Operating expenses	(31.1)	(32)	(57.9)	(65.6)
Segment profit	84.3	104.5	194.7	200.9
Capital expenditures	21.3	17.7	52.9	30
Oklahoma
Segment Reporting
Revenue from contracts with customers	263.1	264.3	527.7	577.1
Realized gain (loss) on derivatives	(1)	1.9	(2)	3.9
Change in fair value of derivatives	0.8	2	(3.3)	0.6
Total revenues	262.9	268.2	522.4	581.6
Cost of sales, exclusive of operating expenses and depreciation and amortization	(135.5)	(130.5)	(283.3)	(324.5)
Operating expenses	(23.9)	(27)	(49.9)	(51.7)
Segment profit	103.5	110.7	189.2	205.4
Capital expenditures	25	22.1	36.8	47.8
North Texas
Segment Reporting
Revenue from contracts with customers	165.1	167.6	333.7	348.5
Realized gain (loss) on derivatives	1.1	6.5	(0.4)	14.6
Change in fair value of derivatives	(1.1)	(7)	(1.2)	(4.3)
Total revenues	165.1	167.1	332.1	358.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	(89)	(75.1)	(170.3)	(164.7)
Operating expenses	(23.7)	(24.7)	(49.6)	(50.7)
Segment profit	52.4	67.3	112.2	143.4
Capital expenditures	7.1	11.8	17.6	29.9
Corporate
Segment Reporting
Revenue from contracts with customers	(425.3)	(381.5)	(875.6)	(824.2)
Realized gain (loss) on derivatives	0	0	0	0
Change in fair value of derivatives	0	0	0	0
Total revenues	(425.3)	(381.5)	(875.6)	(824.2)
Cost of sales, exclusive of operating expenses and depreciation and amortization	425.3	381.5	875.6	824.2
Operating expenses	0	0	0	0
Segment profit	0	0	0	0
Capital expenditures	1.2	1.5	2.1	2.8
Product sales
Segment Reporting
Revenue from contracts with customers	1,278.6	1,239.3	2,683.6	2,715.6
Product sales | Permian
Segment Reporting
Revenue from contracts with customers	419.5	370.8	853.7	687.2
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers	776.4	793.7	1,664.1	1,840
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	54	60	116.7	160.1
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers	28.7	14.8	49.1	28.3
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Natural gas sales
Segment Reporting
Revenue from contracts with customers	177.5	218.5	459	560.9
Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers	15.3	76.4	119.5	205.7
Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers	110.9	92.5	230.5	224.3
Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	19.9	32.9	52.7	99.7
Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers	31.4	16.7	56.3	31.2
Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL sales
Segment Reporting
Revenue from contracts with customers	655.1	647.1	1,410.8	1,513
NGL sales | Permian
Segment Reporting
Revenue from contracts with customers	(6.2)	0	(12.8)	0.4
NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers	665.5	648.6	1,433.6	1,506.5
NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	(0.6)	0.4	(1.6)	9
NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers	(3.6)	(1.9)	(8.4)	(2.9)
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	445.1	373.7	812.6	641.7
Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers	410.4	294.4	747	481.1
Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers	0	52.6	0	109.2
Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	34.7	26.7	65.6	51.4
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
Other
Segment Reporting
Revenue from contracts with customers	0.9		1.2
Other | Permian
Segment Reporting
Revenue from contracts with customers	0		0
Other | Louisiana
Segment Reporting
Revenue from contracts with customers	0		0
Other | Oklahoma
Segment Reporting
Revenue from contracts with customers	0		0
Other | North Texas
Segment Reporting
Revenue from contracts with customers	0.9		1.2
Other | Corporate
Segment Reporting
Revenue from contracts with customers	0		0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	237.6	204.1	495.2	441.6
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	9	5.3	18.6	9.7
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	105.6	102.3	214.3	220.3
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	72.1	69	146	151.2
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(424.3)	(380.7)	(874.1)	(822.8)
Product sales, Natural gas sales—related parties
Segment Reporting
Revenue from contracts with customers			0
Product sales, Natural gas sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers			0
Product sales, Natural gas sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers			0.1
Product sales, Natural gas sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers			0
Product sales, Natural gas sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers			0
Product sales, Natural gas sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers			(0.1)
NGL sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	237.6	204.1	495.2	441.6
NGL sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	9	5.3	18.5	9.7
NGL sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	105.6	102.3	214.3	220.3
NGL sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	68.5	66.2	139.1	145.7
NGL sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(420.7)	(377.9)	(867.1)	(817.3)
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
Crude oil and condensate sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	3.6	2.8	6.9	5.5
Crude oil and condensate sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(3.6)	(2.8)	(6.9)	(5.5)
Midstream services
Segment Reporting
Revenue from contracts with customers	273.3	279.5	545.2	558.8
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers	64	52.4	126.4	97.4
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers	42.5	42.1	85	97.1
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers	103.5	102	196.7	196.7
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers	63.3	83	137.1	167.6
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Gathering and transportation
Segment Reporting
Revenue from contracts with customers	175.2	160.4	340.7	310.6
Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers	41.6	29.3	81.3	52.6
Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers	27.9	18.7	52.3	38.7
Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers	64.7	60.5	120.5	115.3
Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers	41	51.9	86.6	104
Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Processing
Segment Reporting
Revenue from contracts with customers	72.4	81.5	151.2	163.2
Processing | Permian
Segment Reporting
Revenue from contracts with customers	14.5	14.5	31.5	28.5
Processing | Louisiana
Segment Reporting
Revenue from contracts with customers	0.6	0.1	1.2	0.4
Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers	35.4	36.4	69	71.7
Processing | North Texas
Segment Reporting
Revenue from contracts with customers	21.9	30.5	49.5	62.6
Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services
Segment Reporting
Revenue from contracts with customers	13.9	17.5	31.3	45.3
NGL services | Permian
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers	13.9	17.4	31.2	45.2
NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services | North Texas
Segment Reporting
Revenue from contracts with customers	0	0.1	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	9.6	17.7	17.4	34.9
Crude services | Permian
Segment Reporting
Revenue from contracts with customers	6.2	7	10	13
Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers	0	5.6	0.1	12.1
Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers	3.2	4.9	6.9	9.4
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	2.2	2.4	4.6	4.8
Other services | Permian
Segment Reporting
Revenue from contracts with customers	1.7	1.6	3.6	3.3
Other services | Louisiana
Segment Reporting
Revenue from contracts with customers	0.1	0.3	0.2	0.7
Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.2	0.2	0.3	0.3
Other services | North Texas
Segment Reporting
Revenue from contracts with customers	0.2	0.3	0.5	0.5
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
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0	0	0
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	1	0.8	1.5	1.4
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(1)	(0.8)	(1.5)	(1.4)
NGL services—related parties
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0	0	0
NGL services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	1	0.8	1.5	1.4
NGL services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	$ (1)	$ (0.8)	$ (1.5)	$ (1.4)

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Segment Reporting [Abstract]
Segment profit	$ 333.3	$ 374.3	$ 678.2	$ 737.5
Depreciation and amortization	(162.6)	(165.3)	(327.9)	(325.7)
Impairments	0	0	(14.2)	0
Gain on disposition of assets	(0.9)	0.8	0.8	1.2
General and administrative	(30.2)	(27.9)	(85.4)	(57.4)
Interest expense, net of interest income	(66.7)	(68.8)	(132.1)	(137.3)
Income (loss) from unconsolidated affiliate investments	0.3	(4.6)	(0.5)	(4.7)
Other income	3.8	0.4	4.3	0.4
Income (loss) before non-controlling interest and income taxes	$ 77	$ 108.9	$ 123.2	$ 214

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Segment Reporting
Total identifiable assets	$ 8,152.3	$ 8,328.6
Permian
Segment Reporting
Total identifiable assets	2,813	2,813.6
Louisiana
Segment Reporting
Total identifiable assets	2,000.9	2,031.8
Oklahoma
Segment Reporting
Total identifiable assets	2,177.8	2,275.8
North Texas
Segment Reporting
Total identifiable assets	943.7	1,017.7
Corporate
Segment Reporting
Total identifiable assets	$ 216.9	$ 189.7

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Other current assets:
Product inventory	$ 73.3	$ 46.4
Prepaid expenses and other	29.4	19
Other current assets	102.7	65.4
Other current liabilities:
Accrued interest	62.9	63.4
Accrued wages and benefits, including taxes	15.3	23.2
Accrued ad valorem taxes	23.3	33.3
Capital expenditure accruals	41	64.6
Short-term lease liability	36.6	28.2
Operating expense accruals	19.7	21.5
Accrued common unit repurchase	22.9	41.5
Other	27.6	2.8
Other current liabilities	$ 249.3	$ 278.5

Commitments and Contingencies (

Commitments and Contingencies (Details) - Harris County Multi-District Litigation - EnLink Energy GP, LLC	6 Months Ended
	Jun. 30, 2024 claim defendant
Commitments and Contingencies
Number of defendants | defendant	350
Filed cases, over	150
Third party claims, number	90