EnLink Midstream (ENLC) 10-Q 1 May 24 2024 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Mar. 31, 2024	Apr. 25, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 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)		451,304,161
Document Fiscal Period Focus	Q1
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		Mar. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents		$ 16.8	$ 28.7
Accounts receivable:
Trade receivables	[1]	57.5	85.9
Accrued revenue and other		483.5	581.4
Fair value of derivative assets		90.6	76.9
Other current assets		63.7	65.4
Total current assets		712.1	838.3
Property and equipment, net of accumulated depreciation of $5,261.6 and $5,137.2, respectively		6,360.4	6,407
Intangible assets, net of accumulated amortization of $1,083.0 and $1,051.2, respectively		761.8	793.6
Investment in unconsolidated affiliates		159.8	150.5
Fair value of derivative assets—long-term		21.5	27
Other assets, net		112.4	112.2
Total assets		8,128	8,328.6
Current liabilities:
Accounts payable and drafts payable		113	126.5
Accrued natural gas, NGLs, condensate, and crude oil purchases		356.2	428
Fair value of derivative liabilities		98	62.7
Current maturities of long-term debt		97.9	97.9
Other current liabilities		247.9	278.5
Total current liabilities		913	993.6
Long-term debt, net of unamortized issuance cost		4,469.5	4,471
Other long-term liabilities		83.5	98
Deferred tax liability, net		101.1	104.2
Fair value of derivative liabilities		21.8	26.7
Members’ equity:
Members’ equity (448,783,413 and 451,614,086 units issued and outstanding, respectively)		892.5	1,000.5
Accumulated other comprehensive income		3.7	0.7
Non-controlling interest		1,642.9	1,633.9
Total members’ equity		2,539.1	2,635.1
Commitments and contingencies (Note 15)
Total liabilities and members’ equity		$ 8,128	$ 8,328.6
[1] There was no allowance for bad debt at March 31, 2024 and December 31, 2023.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
ASSETS
Property and equipment, accumulated depreciation	$ 5,261.6	$ 5,137.2
Intangible assets, accumulated amortization	$ 1,083	$ 1,051.2
Members’ equity:
Common units issued (in shares)	448,783,413	451,614,086
Common units outstanding (in shares)	451,614,086	448,783,413
Allowance for bad debt	$ 0	$ 0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Revenues:
Revenue from contracts with customers	$ 1,676.9	$ 1,755.6
Revenue, Product and Service [Extensible Enumeration]	Midstream services	Midstream services
Gain (loss) on derivative activity	$ (29)	$ 11.9
Total revenues	1,647.9	1,767.5
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	$ 1,150.4	$ 1,271.9
Cost, Product and Service [Extensible Enumeration]	Midstream services	Midstream services
Operating expenses	$ 152.6	$ 132.4
Depreciation and amortization	165.3	160.4
Impairments	14.2	0
Gain on disposition of assets	(1.7)	(0.4)
General and administrative	55.2	29.5
Total operating costs and expenses	1,536	1,593.8
Operating income	111.9	173.7
Other income (expense):
Interest expense, net of interest income	(65.4)	(68.5)
Loss from unconsolidated affiliate investments	(0.8)	(0.1)
Other income	0.5	0
Total other expense	(65.7)	(68.6)
Income before non-controlling interest and income taxes	46.2	105.1
Income tax benefit (expense)	3.8	(10.9)
Net income	50	94.2
Net income attributable to non-controlling interest	35.5	36
Net income attributable to ENLC	$ 14.5	$ 58.2
Net income attributable to ENLC per unit:
Basic common unit (in dollars per share)	$ 0.03	$ 0.12
Diluted common unit (in dollars per share)	$ 0.03	$ 0.12
Product sales
Revenues:
Revenue from contracts with customers	$ 1,405	$ 1,476.3
Midstream services
Revenues:
Revenue from contracts with customers	$ 271.9	$ 279.3

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2024		Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Net income		$ 50		$ 94.2
Unrealized gain (loss) on designated cash flow hedge	[1]	3	[2]	(1.2)	[3]
Comprehensive income		53		93
Comprehensive income attributable to non-controlling interest		35.5		36
Comprehensive income attributable to ENLC		$ 17.5		$ 57
[1] Includes tax expense of $0.9 million and a tax benefit of $0.4 million for the three months ended March 31, 2024 and 2023, respectively. Includes tax expense of $0.9 million for the three months ended March 31, 2024. Includes a tax benefit of $0.4 million for the three months ended March 31, 2023.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Tax expense (benefit)	$ 0.9	$ (0.4)

Consolidated Statement of Chang

Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Repurchase of Series C Preferred Units	Common Units		Accumulated Other Comprehensive Income (Loss)	Non-Controlling Interest	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		(16.8)			$ (16.8)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)					2,500,000
Unit-based compensation		4			$ 4
Contributions from non-controlling interests		8.4						8.4
Distributions		(104.1)			(61.7)			(42.4)
Unrealized gain (loss) on designated cash flow hedge	[1]	(1.2)	[2]				(1.2)
Repurchase of Series C Preferred Units				$ (3.9)					$ (3.9)
Common units repurchased		$ (51.4)			$ (51.4)
Common units repurchased (in shares)		(4,444,415)			(4,400,000)
Net income		$ 94.2			$ 58.2			36
Member equity, end balance at Mar. 31, 2023		2,841.9			$ 1,238.7		(1.2)	1,604.4
Units outstanding, ending balance (in shares) at Mar. 31, 2023					467,100,000
Member equity, beginning balance at Dec. 31, 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		$ (15.5)			$ (15.5)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)					2,600,000
Unit-based compensation		5.6			$ 5.6
Contributions from non-controlling interests		13						13
Distributions		(101.9)			(62.4)			(39.5)
Unrealized gain (loss) on designated cash flow hedge	[3]	3	[2]				3
Common units repurchased	[4]	(27.1)			$ (27.1)
Common units repurchased		$ (68.6)
Common units repurchased (in shares)		(5,447,442)			(5,400,000)	[4]
Accrued common unit repurchase	[5]	$ (23.1)			$ (23.1)
Net income		50			14.5			35.5
Member equity, end balance at Mar. 31, 2024		$ 2,539.1			$ 892.5		$ 3.7	$ 1,642.9
Units outstanding, ending balance (in shares) at Mar. 31, 2024		448,783,413			448,800,000
[1] Includes a tax benefit of $0.4 million for the three months ended March 31, 2023. Includes tax expense of $0.9 million and a tax benefit of $0.4 million for the three months ended March 31, 2024 and 2023, respectively. Includes tax expense of $0.9 million for the three months ended March 31, 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.”

Consolidated Statement of Cha_2

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

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Cash flows from operating activities:
Net income	$ 50	$ 94.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	165.3	160.4
Gain on disposition of assets	(1.7)	(0.4)
Non-cash unit-based compensation	5.6	4
Non-cash loss on derivatives recognized in net income	26.1	1.4
Amortization of debt issuance costs and net discount of senior unsecured notes	1.5	1.5
Deferred income tax (benefit) expense	(4)	10.8
Loss from unconsolidated affiliate investments	0.8	0.1
Impairments	14.2	0
Other operating activities	(2)	1.7
Changes in assets and liabilities, net of the effects of acquisitions:
Accounts receivable, accrued revenue, and other	126.7	101.1
Product inventory, prepaid expenses, and other	11.3	68.3
Accounts payable, accrued product purchases, and other accrued liabilities	(100.5)	(171)
Net cash provided by operating activities	293.3	272.1
Cash flows from investing activities:
Additions to property and equipment	(110.4)	(100.7)
Contributions to unconsolidated affiliate investments	(9.4)	(49.7)
Other investing activities	(5.7)	0.4
Net cash used in investing activities	(125.5)	(150)
Cash flows from financing activities:
Proceeds from borrowings	629.4	1,173
Repayments on borrowings	(632.4)	(1,067.4)
Distributions to members	(62.4)	(61.7)
Distributions to non-controlling interests	(39.5)	(42.4)
Earnout payments	2.5	0
Payment to redeem mandatorily redeemable non-controlling interest	0	(10.5)
Contributions from non-controlling interests	13	8.4
Common unit repurchases	(68.6)	(51.4)
Conversion of unit-based awards for common units, net of units withheld for taxes	(15.5)	(16.8)
Other financing activities	(1.2)	0.8
Net cash used in financing activities	(179.7)	(71.9)
Net increase (decrease) in cash and cash equivalents	(11.9)	50.2
Cash and cash equivalents, beginning of period	28.7	22.6
Cash and cash equivalents, end of period	16.8	72.8
Supplemental disclosures of cash flow information:
Cash paid for interest	65.8	62.2
Non-cash investing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	11.2	10.4
Non-cash accrual of property and equipment	(7)	13.4
Repurchase of Series C Preferred Units
Cash flows from financing activities:
Repurchase of Series C Preferred Units	$ 0	$ (3.9)

General

General	3 Months Ended
	Mar. 31, 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 March 31, 2024, GIP, through GIP III Stetson I, L.P. and GIP III Stetson II, L.P, owns 45.8% 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 March 31, 2024, our midstream infrastructure network includes approximately 13,600 miles of pipelines, 25 natural gas processing plants with approximately 5.8 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. Our natural gas gathering business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger diameter pipelines for further transmission. Our processing plants remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. We also store natural gas and NGLs on behalf of third parties for a fee or to balance our own purchases and sales in marketing natural gas and NGLs for our customers. Our large diameter natural gas transmission pipelines provide access to multiple domestic production basins to a variety of customers, such as industrial end-users, LNG facilities, and utilities. Our large diameter natural gas transmission pipelines are connected to our gathering systems or third party gathering systems, natural gas transmission pipeline systems, and natural gas storage caverns. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which we transport NGLs from our West Texas and Central Oklahoma operations on third party pipelines to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, in addition to condensate stabilization. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased.

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated minimum volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods. Contractually Committed Fees Commitments 2024 (remaining) $ 116.3 2025 147.9 2026 153.3 2027 125.1 2028 116.4 Thereafter 1,053.0 Total $ 1,712.0 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. Triggering events include, but are not limited to, significant changes in the use of the asset group, current operating results that are significantly less than forecasted results, and negative industry or economic trends, including changes in commodity prices, significant adverse changes in legal or regulatory factors, or an expectation that it is more likely than not that an asset group will be sold before the end of its useful life. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. 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 March 31, 2023. d. 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. We do not expect ASU 2023-07 to have a material impact on our 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	3 Months Ended
	Mar. 31, 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 Three Months Ended March 31, 2024 Customer relationships, beginning of period $ 1,844.8 $ (1,051.2) $ 793.6 Amortization expense — (31.8) (31.8) Customer relationships, end of period $ 1,844.8 $ (1,083.0) $ 761.8 Amortization expense was $31.8 million and $31.9 million for the three months ended March 31, 2024 and 2023, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2024 (remaining) $ 95.8 2025 110.2 2026 106.3 2027 106.3 2028 106.3 Thereafter 236.9 Total $ 761.8

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 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: March 31, 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 2024 2023 Midstream services revenue $ 0.5 $ 0.7 Cost of sales (1.4) (1.5) (b) Transactions with GIP GIP Repurchase Agreement. On February 15, 2022, we entered into an agreement with GIP pursuant to which we agreed to repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders, less broker commissions, which are not paid with respect to the GIP units. The repurchase agreement terminated as of December 31, 2022 in accordance with its terms. On December 20, 2022, we entered into a renewed repurchase agreement with GIP for 2023 (the “Second Repurchase Agreement”) on terms substantially similar to those of the repurchase agreement entered into by the Company and GIP on February 15, 2022. The Second Repurchase Agreement terminated on December 31, 2023. On January 16, 2024, we entered into a new repurchase agreement with GIP with terms substantially similar to the Second Repurchase Agreement. 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. Management believes the foregoing transactions with related parties were executed on terms that are fair and reasonable. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of March 31, 2024 and December 31, 2023, long-term debt consisted of the following (in millions): March 31, 2024 December 31, 2023 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ 150.0 $ — $ 150.0 $ — $ — $ — AR Facility due 2025 (2) 147.0 — 147.0 300.0 — 300.0 ENLK’s 4.40% Senior unsecured notes due 2024 97.9 — 97.9 97.9 — 97.9 ENLK’s 4.15% Senior unsecured notes due 2025 421.6 — 421.6 421.6 — 421.6 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.2) 490.8 491.0 (0.2) 490.8 ENLC’s 5.625% Senior unsecured notes due 2028 500.0 — 500.0 500.0 — 500.0 ENLC’s 5.375% Senior unsecured notes due 2029 498.7 — 498.7 498.7 — 498.7 ENLC’s 6.50% Senior unsecured notes due 2030 1,000.0 (2.6) 997.4 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 $ 4,606.2 $ (8.0) 4,598.2 $ 4,609.2 $ (8.2) 4,601.0 Debt issuance cost (3) (30.8) (32.1) Less: Current maturities of long-term debt (4) (97.9) (97.9) Long-term debt, net of unamortized issuance cost $ 4,469.5 $ 4,471.0 ____________________________ (1) The effective interest rate was 6.9% at March 31, 2024. (2) The effective interest rate was 6.3% and 6.4% at March 31, 2024 and December 31, 2023, respectively. (3) Net of accumulated amortization of $21.4 million and $20.0 million at March 31, 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” on the consolidated balance sheets as of March 31, 2024 and December 31, 2023 as these notes matured on April 1, 2024. 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 $150.0 million in outstanding borrowings under the Revolving Credit Facility and $22.3 million in outstanding letters of credit as of March 31, 2024. At March 31, 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 $497.0 million as of March 31, 2024. As of March 31, 2024, the AR Facility had a borrowing base of $389.1 million and there were $147.0 million in outstanding borrowings under the AR Facility. At March 31, 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	3 Months Ended
	Mar. 31, 2024
Income Tax Disclosure [Abstract]
Income Taxes	(6) Income Taxes The components of our income tax benefit (expense) are as follows (in millions): Three Months Ended 2024 2023 Current income tax expense $ (0.2) $ (0.1) Deferred income tax benefit (expense) 4.0 (10.8) Income tax benefit (expense) $ 3.8 $ (10.9) The following schedule reconciles income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions): Three Months Ended 2024 2023 Expected income tax expense based on federal statutory tax rate $ (2.2) $ (14.5) State income tax expense, net of federal benefit (0.4) (1.8) Unit-based compensation (1) 7.3 6.5 Other (0.9) (1.1) Income tax benefit (expense) $ 3.8 $ (10.9) ____________________________ (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 March 31, 2024, we had $774.0 million of deferred tax assets, net of a $1.2 million valuation allowance, and $875.1 million of deferred tax liabilities for net deferred tax liabilities of $101.1 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. We provide a valuation allowance, if necessary, to reduce deferred tax assets, if all, or some portion, of such assets will more than likely not be realized. As of March 31, 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	3 Months Ended
	Mar. 31, 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 March 31, 2024 and December 31, 2023, there were 54,712,077 and 54,575,638 Series B Preferred Units issued and outstanding, respectively. 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 three months ended March 31, 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 2023 Fourth Quarter of 2022 — $ 17.3 February 13, 2023 First Quarter of 2023 135,421 $ 15.2 May 12, 2023 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 March 31, 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 $7.05 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 March 31, 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 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 ____________________________ (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	3 Months Ended
	Mar. 31, 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 ____________________________ (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 2024 2023 Publicly held ENLC common units 2,166,805 2,207,305 ENLC common units held by GIP (1) 3,280,637 2,237,110 Total ENLC common units 5,447,442 4,444,415 Aggregate cost for publicly held ENLC common units $ 26.9 $ 26.8 Aggregate cost for ENLC common units held by GIP 41.5 24.6 Excise tax on common unit repurchases 0.2 — Total aggregate cost for ENLC common units $ 68.6 $ 51.4 Average price paid per publicly held ENLC common unit (2) $ 12.41 $ 12.14 Average price paid per ENLC common unit held by GIP (2)(3) $ 12.66 $ 11.01 ____________________________ (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 April 29, 2024, we repurchased 1,862,695 ENLC common units held by GIP at an aggregate cost of $23.1 million, or an average of $12.40 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 March 31, 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 March 31, 2024, $23.1 million is classified as “Other current liabilities” on 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 2024 2023 Distributed earnings allocated to: Common units (1) $ 59.8 $ 58.6 Unvested unit-based awards (1) 0.7 0.9 Total distributed earnings $ 60.5 $ 59.5 Undistributed loss allocated to: Common units $ (45.4) $ (1.3) Unvested unit-based awards (0.6) — Total undistributed loss $ (46.0) $ (1.3) Net income attributable to ENLC allocated to: Common units $ 14.4 $ 57.3 Unvested unit-based awards 0.1 0.9 Total net income attributable to ENLC $ 14.5 $ 58.2 Net income attributable to ENLC per unit: Basic $ 0.03 $ 0.12 Diluted $ 0.03 $ 0.12 ____________________________ (1) Represents distribution activity consistent with the distribution activity table below. The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended 2024 2023 Basic weighted average units outstanding: Weighted average common units outstanding 451.3 468.9 Diluted weighted average units outstanding: Weighted average basic common units outstanding 451.3 468.9 Dilutive effect of unvested restricted units 2.9 4.4 Total weighted average diluted common units outstanding 454.2 473.3 All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. c. Distributions A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 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 2023 Fourth Quarter of 2022 $ 0.1250 February 13, 2023 First Quarter of 2023 $ 0.1250 May 12, 2023

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates As of March 31, 2024, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended 2024 2023 GCF Contributions $ 9.4 $ 6.2 Equity in loss $ (1.8) $ (1.1) Cedar Cove JV Distributions $ — $ (0.1) Equity in loss $ (0.7) $ (0.6) Matterhorn JV Contributions $ — $ 43.5 Equity in income $ 1.7 $ 1.6 Total Contributions $ 9.4 $ 49.7 Distributions $ — $ (0.1) Equity in loss $ (0.8) $ (0.1) The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2024 and December 31, 2023 (in millions): March 31, 2024 December 31, 2023 GCF $ 52.1 $ 44.5 Cedar Cove JV (1) (8.0) (7.3) Matterhorn JV 107.7 106.0 Total investment in unconsolidated affiliates $ 151.8 $ 143.2 ____________________________ (1)

Employee Incentive Plans

Employee Incentive Plans	3 Months Ended
	Mar. 31, 2024
Share-Based Payment Arrangement [Abstract]
Employee Incentive Plans	(10) Employee Incentive Plans a. Long-Term Incentive Plans We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended 2024 2023 Cost of unit-based compensation charged to operating expense $ 0.9 $ 0.9 Cost of unit-based compensation charged to general and administrative expense 4.7 3.1 Total unit-based compensation expense $ 5.6 $ 4.0 Amount of related income tax benefit recognized in net income (1) $ 1.3 $ 0.9 ____________________________ (1) The amount of related income tax benefit recognized in net income excluded book-to-tax differences recorded upon the vesting of unit-based awards. For additional information, see “Note 6—Income Taxes.” b. Restricted Incentive Units The restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2024 is provided below: Three Months Ended Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 5,445,980 $ 7.27 Granted (1) 1,343,217 12.36 Vested (1)(2) (2,309,954) 3.94 Forfeited (5,397) 9.96 Unvested, end of period 4,473,846 $ 10.51 Aggregate intrinsic value, end of period (in millions) $ 61.0 ____________________________ (1) Beginning in 2024, restricted incentive units awarded typically vest on a graded vesting schedule over three years. Prior to 2024, restricted incentive units awarded typically vested at the end of three years. (2) Vested units included 680,384 ENLC common units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2024 and 2023 is provided below (in millions): Three Months Ended Restricted Incentive Units: 2024 2023 Aggregate intrinsic value of units vested $ 28.1 $ 27.1 Fair value of units vested $ 9.1 $ 13.4 As of March 31, 2024, there were $29.7 million of unrecognized compensation costs that related to unvested restricted incentive units. These costs are expected to be recognized over a weighted average period of 2.1 years. c. Performance Units We grant performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. The following table presents a summary of the performance units: Three Months Ended Performance Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 2,236,744 $ 6.37 Granted 508,586 12.92 Vested (1) (1,061,232) 4.77 Forfeited (39,052) 11.84 Unvested, end of period 1,645,046 $ 9.30 Aggregate intrinsic value, end of period (in millions) $ 22.4 ____________________________ (1) Vested units included 576,040 ENLC common units withheld for payroll taxes paid on behalf of employees. A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2024 and 2023 is provided below (in millions). Three Months Ended Performance Units: 2024 2023 Aggregate intrinsic value of units vested $ 19.2 $ 22.0 Fair value of units vested $ 5.1 $ 8.1 As of March 31, 2024, there were $13.4 million of unrecognized compensation costs that related to unvested performance units. These costs are expected to be recognized over a weighted average period of 2.0 years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: Performance Units: February 2024 Grant-date fair value $ 12.92 Beginning TSR Price $ 12.74 Risk-free interest rate 4.46 % Volatility factor 41.51 %

Derivatives

Derivatives	3 Months Ended
	Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(11) 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. 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 (loss) 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 2024 2023 Change in fair value of interest rate swap $ 3.9 $ (1.6) Tax benefit (expense) (0.9) 0.4 Unrealized gain (loss) on designated cash flow hedge $ 3.0 $ (1.2) The fair value of derivative assets and liabilities related to the interest rate swap are as follows (in millions): March 31, 2024 December 31, 2023 Fair value of derivative assets—current $ 4.3 $ 3.3 Fair value of derivative assets—long-term 0.5 — Fair value of derivative liabilities—long-term — (2.4) Net fair value of interest rate swap $ 4.8 $ 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 2024 2023 Interest income $ 1.5 $ 0.5 We expect to recognize an additional $4.3 million of interest income out of accumulated other comprehensive income (loss) over the next twelve months. Commodity Derivatives The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity derivatives are as follows (in millions): Three Months Ended 2024 2023 Change in fair value of derivatives $ (26.1) $ (1.4) Realized gain (loss) on derivatives (2.9) 13.3 Gain (loss) on derivative activity $ (29.0) $ 11.9 The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): March 31, 2024 December 31, 2023 Fair value of derivative assets—current $ 86.3 $ 73.6 Fair value of derivative assets—long-term 21.0 27.0 Fair value of derivative liabilities—current (98.0) (62.7) Fair value of derivative liabilities—long-term (21.8) (24.3) Net fair value of commodity derivatives $ (12.5) $ 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 March 31, 2024 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028. Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps MMgals (136.1) $ (16.3) NGL (long contracts) Swaps MMgals 72.5 (2.1) Natural gas (short contracts) Swaps and futures Bbtu (143.1) 87.4 Natural gas (long contracts) Swaps and futures Bbtu 119.0 (81.4) Crude and condensate (short contracts) Swaps and futures MMbbls (7.2) (7.8) Crude and condensate (long contracts) Swaps and futures MMbbls 0.9 7.7 Total fair value of commodity derivatives $ (12.5) 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 $107.3 million as of March 31, 2024 would be reduced to $4.2 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	3 Months Ended
	Mar. 31, 2024
Fair Value Disclosures [Abstract]
Fair Value Measurements	(12) Fair Value Measurements Derivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 March 31, 2024 December 31, 2023 Interest rate swap (1) $ 4.8 $ 0.9 Commodity derivatives (2) $ (12.5) $ 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): March 31, 2024 December 31, 2023 Carrying Value Fair Carrying Value Fair Long-term debt, including current maturities of long-term debt (1) $ 4,567.4 $ 4,424.8 $ 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 $30.8 million and $32.1 million as of March 31, 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 March 31, 2024 and December 31, 2023 were based on Level 2 inputs from third-party market quotations. Contingent Consideration. The carrying value and estimated fair value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities are disclosed below (in millions): Three Months Ended 2024 2023 Amarillo Rattler Acquisition contingent consideration (1) Contingent consideration liability, beginning of period $ 4.8 $ 4.2 Change in fair value 1.4 0.5 Earnout payments (2.3) — Contingent consideration liability, end of period $ 3.9 $ 4.7 Central Oklahoma Acquisition contingent consideration (2) Contingent consideration liability, beginning of period $ 1.9 $ 1.3 Change in fair value 0.3 0.2 Earnout payments (0.2) — Contingent consideration liability, end of period $ 2.0 $ 1.5 Total contingent consideration (1)(2) Contingent consideration liability, beginning of period $ 6.7 $ 5.5 Change in fair value 1.7 0.7 Earnout payments (2.5) — Contingent consideration liability, end of period $ 5.9 $ 6.2 ____________________________ (1) Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity exceeding historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. The carrying value of the contingent consideration is equal to its fair value. (2) Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. The carrying value of the contingent consideration is equal to its fair value. 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	3 Months Ended
	Mar. 31, 2024
Segment Reporting [Abstract]
Segment Information	(13) 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 and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended March 31, 2024 Natural gas sales $ 104.2 $ 119.6 $ 32.8 $ 24.9 $ — $ 281.5 NGL sales (6.6) 768.1 (1.0) (4.8) — 755.7 Crude oil and condensate sales 336.6 — 30.9 — — 367.5 Other — — — 0.3 — 0.3 Product sales 434.2 887.7 62.7 20.4 — 1,405.0 Natural gas sales—related parties — 0.1 — — (0.1) — NGL sales—related parties 257.6 9.5 108.7 70.6 (446.4) — Crude oil and condensate sales—related parties — — — 3.3 (3.3) — Product sales—related parties 257.6 9.6 108.7 73.9 (449.8) — Gathering and transportation 39.7 24.4 55.8 45.6 — 165.5 Processing 17.0 0.6 33.6 27.6 — 78.8 NGL services — 17.3 — 0.1 — 17.4 Crude services 3.8 0.1 3.7 0.2 — 7.8 Other services 1.9 0.1 0.1 0.3 — 2.4 Midstream services 62.4 42.5 93.2 73.8 — 271.9 NGL services—related parties — — — 0.5 (0.5) — Midstream services—related parties — — — 0.5 (0.5) — Revenue from contracts with customers 754.2 939.8 264.6 168.6 (450.3) 1,676.9 Realized gain (loss) on derivatives (6.8) 6.4 (1.0) (1.5) — (2.9) Change in fair value of derivatives (2.4) (19.5) (4.1) (0.1) — (26.1) Total revenues 745.0 926.7 259.5 167.0 (450.3) 1,647.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (582.1) (789.5) (147.8) (81.3) 450.3 (1,150.4) Adjusted gross margin 162.9 137.2 111.7 85.7 — 497.5 Operating expenses (73.9) (26.8) (26.0) (25.9) — (152.6) Segment profit 89.0 110.4 85.7 59.8 — 344.9 Depreciation and amortization (43.6) (35.1) (56.5) (28.5) (1.6) (165.3) Gross margin 45.4 75.3 29.2 31.3 (1.6) 179.6 Impairments — — — (14.2) — (14.2) Gain on disposition of assets — 1.7 — — — 1.7 General and administrative — — — — (55.2) (55.2) Interest expense, net of interest income — — — — (65.4) (65.4) Loss from unconsolidated affiliate investments — — — — (0.8) (0.8) Other income — — — — 0.5 0.5 Income (loss) before non-controlling interest and income taxes $ 45.4 $ 77.0 $ 29.2 $ 17.1 $ (122.5) $ 46.2 Capital expenditures $ 48.6 $ 31.6 $ 11.8 $ 10.5 $ 0.9 $ 103.4 Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended March 31, 2023 Natural gas sales $ 129.3 $ 131.8 $ 66.8 $ 14.5 $ — $ 342.4 NGL sales 0.4 857.9 8.6 (1.0) — 865.9 Crude oil and condensate sales 186.7 56.6 24.7 — — 268.0 Product sales 316.4 1,046.3 100.1 13.5 — 1,476.3 NGL sales—related parties 237.5 4.4 118.0 79.5 (439.4) — Crude oil and condensate sales—related parties — — — 2.7 (2.7) — Product sales—related parties 237.5 4.4 118.0 82.2 (442.1) — Gathering and transportation 23.3 20.0 54.8 52.1 — 150.2 Processing 14.0 0.3 35.3 32.1 — 81.7 NGL services — 27.8 — — — 27.8 Crude services 6.0 6.5 4.5 0.2 — 17.2 Other services 1.7 0.4 0.1 0.2 — 2.4 Midstream services 45.0 55.0 94.7 84.6 — 279.3 NGL services—related parties — — — 0.6 (0.6) — Midstream services—related parties — — — 0.6 (0.6) — Revenue from contracts with customers 598.9 1,105.7 312.8 180.9 (442.7) 1,755.6 Realized gain (loss) on derivatives (4.0) 7.2 2.0 8.1 — 13.3 Change in fair value of derivatives 6.3 (9.0) (1.4) 2.7 — (1.4) Total revenues 601.2 1,103.9 313.4 191.7 (442.7) 1,767.5 Cost of sales, exclusive of operating expenses and depreciation and amortization (457.1) (973.9) (194.0) (89.6) 442.7 (1,271.9) Adjusted gross margin 144.1 130.0 119.4 102.1 — 495.6 Operating expenses (48.1) (33.6) (24.7) (26.0) — (132.4) Segment profit 96.0 96.4 94.7 76.1 — 363.2 Depreciation and amortization (40.0) (38.3) (51.9) (28.8) (1.4) (160.4) Gross margin 56.0 58.1 42.8 47.3 (1.4) 202.8 Gain on disposition of assets — 0.1 0.2 0.1 — 0.4 General and administrative — — — — (29.5) (29.5) Interest expense, net of interest income — — — — (68.5) (68.5) Loss from unconsolidated affiliate investments — — — — (0.1) (0.1) Income (loss) before non-controlling interest and income taxes $ 56.0 $ 58.2 $ 43.0 $ 47.4 $ (99.5) $ 105.1 Capital expenditures $ 56.7 $ 12.3 $ 25.7 $ 18.1 $ 1.3 $ 114.1 The table below represents information about segment assets as of March 31, 2024 and December 31, 2023 (in millions): Segment Identifiable Assets: March 31, 2024 December 31, 2023 Permian $ 2,784.9 $ 2,813.6 Louisiana 1,963.8 2,031.8 Oklahoma 2,214.0 2,275.8 North Texas 962.6 1,017.7 Corporate (1) 202.7 189.7 Total identifiable assets $ 8,128.0 $ 8,328.6 ____________________________ (1)

Other Information

Other Information	3 Months Ended
	Mar. 31, 2024
Other Liabilities Disclosure [Abstract]
Other Information	(14) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: March 31, 2024 December 31, 2023 Product inventory $ 40.4 $ 46.4 Prepaid expenses and other 23.3 19.0 Other current assets $ 63.7 $ 65.4 Other current liabilities: March 31, 2024 December 31, 2023 Accrued interest $ 63.6 $ 63.4 Accrued wages and benefits, including taxes 12.7 23.2 Accrued ad valorem taxes 12.1 33.3 Capital expenditure accruals 56.3 64.6 Short-term lease liability 32.7 28.2 Operating expense accruals 21.0 21.5 Accrued common unit repurchase 23.1 41.5 Other 26.4 2.8 Other current liabilities $ 247.9 $ 278.5

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(15) Commitments and Contingencies In February 2021, the areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days (“Winter Storm Uri”). As a result of Winter Storm Uri, we have encountered customer billing disputes related to the delivery of natural gas during the storm, including one that resulted in litigation. The litigation is between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC (“Koch”) in the 162nd District Court in Dallas County, Texas. In April 2024, we reached an agreement to settle this matter and dismiss the claims related to this dispute. 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
	Mar. 31, 2024	Mar. 31, 2023
Pay vs Performance Disclosure
Net Income (Loss) Attributable to Parent	$ 14.5	$ 58.2

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Mar. 31, 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)	3 Months Ended
	Mar. 31, 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated minimum volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.
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. Triggering events include, but are not limited to, significant changes in the use of the asset group, current operating results that are significantly less than forecasted results, and negative industry or economic trends, including changes in commodity prices, significant adverse changes in legal or regulatory factors, or an expectation that it is more likely than not that an asset group will be sold before the end of its useful life. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.
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. We do not expect ASU 2023-07 to have a material impact on our 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)	3 Months Ended
	Mar. 31, 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated minimum volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods. Contractually Committed Fees Commitments 2024 (remaining) $ 116.3 2025 147.9 2026 153.3 2027 125.1 2028 116.4 Thereafter 1,053.0 Total $ 1,712.0

Intangible Assets (Tables)

Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 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 Three Months Ended March 31, 2024 Customer relationships, beginning of period $ 1,844.8 $ (1,051.2) $ 793.6 Amortization expense — (31.8) (31.8) Customer relationships, end of period $ 1,844.8 $ (1,083.0) $ 761.8 Amortization expense was $31.8 million and $31.9 million for the three months ended March 31, 2024 and 2023, respectively.
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2024 (remaining) $ 95.8 2025 110.2 2026 106.3 2027 106.3 2028 106.3 Thereafter 236.9 Total $ 761.8

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 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: March 31, 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 2024 2023 Midstream services revenue $ 0.5 $ 0.7 Cost of sales (1.4) (1.5)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
Summary of Debt	As of March 31, 2024 and December 31, 2023, long-term debt consisted of the following (in millions): March 31, 2024 December 31, 2023 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ 150.0 $ — $ 150.0 $ — $ — $ — AR Facility due 2025 (2) 147.0 — 147.0 300.0 — 300.0 ENLK’s 4.40% Senior unsecured notes due 2024 97.9 — 97.9 97.9 — 97.9 ENLK’s 4.15% Senior unsecured notes due 2025 421.6 — 421.6 421.6 — 421.6 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.2) 490.8 491.0 (0.2) 490.8 ENLC’s 5.625% Senior unsecured notes due 2028 500.0 — 500.0 500.0 — 500.0 ENLC’s 5.375% Senior unsecured notes due 2029 498.7 — 498.7 498.7 — 498.7 ENLC’s 6.50% Senior unsecured notes due 2030 1,000.0 (2.6) 997.4 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 $ 4,606.2 $ (8.0) 4,598.2 $ 4,609.2 $ (8.2) 4,601.0 Debt issuance cost (3) (30.8) (32.1) Less: Current maturities of long-term debt (4) (97.9) (97.9) Long-term debt, net of unamortized issuance cost $ 4,469.5 $ 4,471.0 ____________________________ (1) The effective interest rate was 6.9% at March 31, 2024. (2) The effective interest rate was 6.3% and 6.4% at March 31, 2024 and December 31, 2023, respectively. (3) Net of accumulated amortization of $21.4 million and $20.0 million at March 31, 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” on the consolidated balance sheets as of March 31, 2024 and December 31, 2023 as these notes matured on April 1, 2024.

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax benefit (expense) are as follows (in millions): Three Months Ended 2024 2023 Current income tax expense $ (0.2) $ (0.1) Deferred income tax benefit (expense) 4.0 (10.8) Income tax benefit (expense) $ 3.8 $ (10.9)
Reconciliation of Total Income Tax Expense to Income before Income Taxes	The following schedule reconciles income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions): Three Months Ended 2024 2023 Expected income tax expense based on federal statutory tax rate $ (2.2) $ (14.5) State income tax expense, net of federal benefit (0.4) (1.8) Unit-based compensation (1) 7.3 6.5 Other (0.9) (1.1) Income tax benefit (expense) $ 3.8 $ (10.9) ____________________________ (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)	3 Months Ended
	Mar. 31, 2024
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 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 2023 Fourth Quarter of 2022 — $ 17.3 February 13, 2023 First Quarter of 2023 135,421 $ 15.2 May 12, 2023 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 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 ____________________________ (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)	3 Months Ended
	Mar. 31, 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 ____________________________ (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 2024 2023 Publicly held ENLC common units 2,166,805 2,207,305 ENLC common units held by GIP (1) 3,280,637 2,237,110 Total ENLC common units 5,447,442 4,444,415 Aggregate cost for publicly held ENLC common units $ 26.9 $ 26.8 Aggregate cost for ENLC common units held by GIP 41.5 24.6 Excise tax on common unit repurchases 0.2 — Total aggregate cost for ENLC common units $ 68.6 $ 51.4 Average price paid per publicly held ENLC common unit (2) $ 12.41 $ 12.14 Average price paid per ENLC common unit held by GIP (2)(3) $ 12.66 $ 11.01 ____________________________ (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 2024 2023 Distributed earnings allocated to: Common units (1) $ 59.8 $ 58.6 Unvested unit-based awards (1) 0.7 0.9 Total distributed earnings $ 60.5 $ 59.5 Undistributed loss allocated to: Common units $ (45.4) $ (1.3) Unvested unit-based awards (0.6) — Total undistributed loss $ (46.0) $ (1.3) Net income attributable to ENLC allocated to: Common units $ 14.4 $ 57.3 Unvested unit-based awards 0.1 0.9 Total net income attributable to ENLC $ 14.5 $ 58.2 Net income attributable to ENLC per unit: Basic $ 0.03 $ 0.12 Diluted $ 0.03 $ 0.12 ____________________________ (1) Represents distribution activity consistent with the distribution activity table below. The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended 2024 2023 Basic weighted average units outstanding: Weighted average common units outstanding 451.3 468.9 Diluted weighted average units outstanding: Weighted average basic common units outstanding 451.3 468.9 Dilutive effect of unvested restricted units 2.9 4.4 Total weighted average diluted common units outstanding 454.2 473.3
Summary of Distribution Activity	A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 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 2023 Fourth Quarter of 2022 $ 0.1250 February 13, 2023 First Quarter of 2023 $ 0.1250 May 12, 2023

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
Activity Related to Investment in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended 2024 2023 GCF Contributions $ 9.4 $ 6.2 Equity in loss $ (1.8) $ (1.1) Cedar Cove JV Distributions $ — $ (0.1) Equity in loss $ (0.7) $ (0.6) Matterhorn JV Contributions $ — $ 43.5 Equity in income $ 1.7 $ 1.6 Total Contributions $ 9.4 $ 49.7 Distributions $ — $ (0.1) Equity in loss $ (0.8) $ (0.1) The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2024 and December 31, 2023 (in millions): March 31, 2024 December 31, 2023 GCF $ 52.1 $ 44.5 Cedar Cove JV (1) (8.0) (7.3) Matterhorn JV 107.7 106.0 Total investment in unconsolidated affiliates $ 151.8 $ 143.2 ____________________________ (1)

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	3 Months Ended
	Mar. 31, 2024
Share-Based Payment Arrangement [Abstract]
Schedule of Amounts Recognized in Consolidated Financial Statements	Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended 2024 2023 Cost of unit-based compensation charged to operating expense $ 0.9 $ 0.9 Cost of unit-based compensation charged to general and administrative expense 4.7 3.1 Total unit-based compensation expense $ 5.6 $ 4.0 Amount of related income tax benefit recognized in net income (1) $ 1.3 $ 0.9 ____________________________ (1) The amount of related income tax benefit recognized in net income excluded book-to-tax differences recorded upon the vesting of unit-based awards. For additional information, see “Note 6—Income Taxes.”
Summary of Restricted Incentive Unit Activity	A summary of the restricted incentive unit activity for the three months ended March 31, 2024 is provided below: Three Months Ended Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 5,445,980 $ 7.27 Granted (1) 1,343,217 12.36 Vested (1)(2) (2,309,954) 3.94 Forfeited (5,397) 9.96 Unvested, end of period 4,473,846 $ 10.51 Aggregate intrinsic value, end of period (in millions) $ 61.0 ____________________________ (1) Beginning in 2024, restricted incentive units awarded typically vest on a graded vesting schedule over three years. Prior to 2024, restricted incentive units awarded typically vested at the end of three years. (2)
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units, Vested and Fair Value Vested, ENLC	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2024 and 2023 is provided below (in millions): Three Months Ended Restricted Incentive Units: 2024 2023 Aggregate intrinsic value of units vested $ 28.1 $ 27.1 Fair value of units vested $ 9.1 $ 13.4
Summary of Performance Units, ENLC	The following table presents a summary of the performance units: Three Months Ended Performance Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 2,236,744 $ 6.37 Granted 508,586 12.92 Vested (1) (1,061,232) 4.77 Forfeited (39,052) 11.84 Unvested, end of period 1,645,046 $ 9.30 Aggregate intrinsic value, end of period (in millions) $ 22.4 ____________________________ (1) Vested units included 576,040 ENLC common units withheld for payroll taxes paid on behalf of employees. A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2024 and 2023 is provided below (in millions). Three Months Ended Performance Units: 2024 2023 Aggregate intrinsic value of units vested $ 19.2 $ 22.0 Fair value of units vested $ 5.1 $ 8.1
Summary of Grant-Date Fair Values	The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: Performance Units: February 2024 Grant-date fair value $ 12.92 Beginning TSR Price $ 12.74 Risk-free interest rate 4.46 % Volatility factor 41.51 %

Derivatives (Tables)

Derivatives (Tables)	3 Months Ended
	Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of the unrealized gain (loss) on designated cash flow hedge related to changes in the fair value of our interest rate swap are as follows (in millions): Three Months Ended 2024 2023 Change in fair value of interest rate swap $ 3.9 $ (1.6) Tax benefit (expense) (0.9) 0.4 Unrealized gain (loss) on designated cash flow hedge $ 3.0 $ (1.2) 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 2024 2023 Interest income $ 1.5 $ 0.5 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 2024 2023 Change in fair value of derivatives $ (26.1) $ (1.4) Realized gain (loss) on derivatives (2.9) 13.3 Gain (loss) on derivative activity $ (29.0) $ 11.9
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): March 31, 2024 December 31, 2023 Fair value of derivative assets—current $ 4.3 $ 3.3 Fair value of derivative assets—long-term 0.5 — Fair value of derivative liabilities—long-term — (2.4) Net fair value of interest rate swap $ 4.8 $ 0.9 The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): March 31, 2024 December 31, 2023 Fair value of derivative assets—current $ 86.3 $ 73.6 Fair value of derivative assets—long-term 21.0 27.0 Fair value of derivative liabilities—current (98.0) (62.7) Fair value of derivative liabilities—long-term (21.8) (24.3) Net fair value of commodity derivatives $ (12.5) $ 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 March 31, 2024 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028. Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps MMgals (136.1) $ (16.3) NGL (long contracts) Swaps MMgals 72.5 (2.1) Natural gas (short contracts) Swaps and futures Bbtu (143.1) 87.4 Natural gas (long contracts) Swaps and futures Bbtu 119.0 (81.4) Crude and condensate (short contracts) Swaps and futures MMbbls (7.2) (7.8) Crude and condensate (long contracts) Swaps and futures MMbbls 0.9 7.7 Total fair value of commodity derivatives $ (12.5)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2024 December 31, 2023 Interest rate swap (1) $ 4.8 $ 0.9 Commodity derivatives (2) $ (12.5) $ 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): March 31, 2024 December 31, 2023 Carrying Value Fair Carrying Value Fair Long-term debt, including current maturities of long-term debt (1) $ 4,567.4 $ 4,424.8 $ 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 $30.8 million and $32.1 million as of March 31, 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 March 31, 2024 and December 31, 2023 were based on Level 2 inputs from third-party market quotations. Contingent Consideration. The carrying value and estimated fair value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities are disclosed below (in millions): Three Months Ended 2024 2023 Amarillo Rattler Acquisition contingent consideration (1) Contingent consideration liability, beginning of period $ 4.8 $ 4.2 Change in fair value 1.4 0.5 Earnout payments (2.3) — Contingent consideration liability, end of period $ 3.9 $ 4.7 Central Oklahoma Acquisition contingent consideration (2) Contingent consideration liability, beginning of period $ 1.9 $ 1.3 Change in fair value 0.3 0.2 Earnout payments (0.2) — Contingent consideration liability, end of period $ 2.0 $ 1.5 Total contingent consideration (1)(2) Contingent consideration liability, beginning of period $ 6.7 $ 5.5 Change in fair value 1.7 0.7 Earnout payments (2.5) — Contingent consideration liability, end of period $ 5.9 $ 6.2 ____________________________ (1) Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity exceeding historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. The carrying value of the contingent consideration is equal to its fair value. (2) Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. The carrying value of the contingent consideration is equal to its fair value.

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2024
Segment Reporting [Abstract]
Summary of Financial Information	We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended March 31, 2024 Natural gas sales $ 104.2 $ 119.6 $ 32.8 $ 24.9 $ — $ 281.5 NGL sales (6.6) 768.1 (1.0) (4.8) — 755.7 Crude oil and condensate sales 336.6 — 30.9 — — 367.5 Other — — — 0.3 — 0.3 Product sales 434.2 887.7 62.7 20.4 — 1,405.0 Natural gas sales—related parties — 0.1 — — (0.1) — NGL sales—related parties 257.6 9.5 108.7 70.6 (446.4) — Crude oil and condensate sales—related parties — — — 3.3 (3.3) — Product sales—related parties 257.6 9.6 108.7 73.9 (449.8) — Gathering and transportation 39.7 24.4 55.8 45.6 — 165.5 Processing 17.0 0.6 33.6 27.6 — 78.8 NGL services — 17.3 — 0.1 — 17.4 Crude services 3.8 0.1 3.7 0.2 — 7.8 Other services 1.9 0.1 0.1 0.3 — 2.4 Midstream services 62.4 42.5 93.2 73.8 — 271.9 NGL services—related parties — — — 0.5 (0.5) — Midstream services—related parties — — — 0.5 (0.5) — Revenue from contracts with customers 754.2 939.8 264.6 168.6 (450.3) 1,676.9 Realized gain (loss) on derivatives (6.8) 6.4 (1.0) (1.5) — (2.9) Change in fair value of derivatives (2.4) (19.5) (4.1) (0.1) — (26.1) Total revenues 745.0 926.7 259.5 167.0 (450.3) 1,647.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (582.1) (789.5) (147.8) (81.3) 450.3 (1,150.4) Adjusted gross margin 162.9 137.2 111.7 85.7 — 497.5 Operating expenses (73.9) (26.8) (26.0) (25.9) — (152.6) Segment profit 89.0 110.4 85.7 59.8 — 344.9 Depreciation and amortization (43.6) (35.1) (56.5) (28.5) (1.6) (165.3) Gross margin 45.4 75.3 29.2 31.3 (1.6) 179.6 Impairments — — — (14.2) — (14.2) Gain on disposition of assets — 1.7 — — — 1.7 General and administrative — — — — (55.2) (55.2) Interest expense, net of interest income — — — — (65.4) (65.4) Loss from unconsolidated affiliate investments — — — — (0.8) (0.8) Other income — — — — 0.5 0.5 Income (loss) before non-controlling interest and income taxes $ 45.4 $ 77.0 $ 29.2 $ 17.1 $ (122.5) $ 46.2 Capital expenditures $ 48.6 $ 31.6 $ 11.8 $ 10.5 $ 0.9 $ 103.4 Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended March 31, 2023 Natural gas sales $ 129.3 $ 131.8 $ 66.8 $ 14.5 $ — $ 342.4 NGL sales 0.4 857.9 8.6 (1.0) — 865.9 Crude oil and condensate sales 186.7 56.6 24.7 — — 268.0 Product sales 316.4 1,046.3 100.1 13.5 — 1,476.3 NGL sales—related parties 237.5 4.4 118.0 79.5 (439.4) — Crude oil and condensate sales—related parties — — — 2.7 (2.7) — Product sales—related parties 237.5 4.4 118.0 82.2 (442.1) — Gathering and transportation 23.3 20.0 54.8 52.1 — 150.2 Processing 14.0 0.3 35.3 32.1 — 81.7 NGL services — 27.8 — — — 27.8 Crude services 6.0 6.5 4.5 0.2 — 17.2 Other services 1.7 0.4 0.1 0.2 — 2.4 Midstream services 45.0 55.0 94.7 84.6 — 279.3 NGL services—related parties — — — 0.6 (0.6) — Midstream services—related parties — — — 0.6 (0.6) — Revenue from contracts with customers 598.9 1,105.7 312.8 180.9 (442.7) 1,755.6 Realized gain (loss) on derivatives (4.0) 7.2 2.0 8.1 — 13.3 Change in fair value of derivatives 6.3 (9.0) (1.4) 2.7 — (1.4) Total revenues 601.2 1,103.9 313.4 191.7 (442.7) 1,767.5 Cost of sales, exclusive of operating expenses and depreciation and amortization (457.1) (973.9) (194.0) (89.6) 442.7 (1,271.9) Adjusted gross margin 144.1 130.0 119.4 102.1 — 495.6 Operating expenses (48.1) (33.6) (24.7) (26.0) — (132.4) Segment profit 96.0 96.4 94.7 76.1 — 363.2 Depreciation and amortization (40.0) (38.3) (51.9) (28.8) (1.4) (160.4) Gross margin 56.0 58.1 42.8 47.3 (1.4) 202.8 Gain on disposition of assets — 0.1 0.2 0.1 — 0.4 General and administrative — — — — (29.5) (29.5) Interest expense, net of interest income — — — — (68.5) (68.5) Loss from unconsolidated affiliate investments — — — — (0.1) (0.1) Income (loss) before non-controlling interest and income taxes $ 56.0 $ 58.2 $ 43.0 $ 47.4 $ (99.5) $ 105.1 Capital expenditures $ 56.7 $ 12.3 $ 25.7 $ 18.1 $ 1.3 $ 114.1
Schedule of Segment Assets	The table below represents information about segment assets as of March 31, 2024 and December 31, 2023 (in millions): Segment Identifiable Assets: March 31, 2024 December 31, 2023 Permian $ 2,784.9 $ 2,813.6 Louisiana 1,963.8 2,031.8 Oklahoma 2,214.0 2,275.8 North Texas 962.6 1,017.7 Corporate (1) 202.7 189.7 Total identifiable assets $ 8,128.0 $ 8,328.6 ____________________________ (1)

Other Information (Tables)

Other Information (Tables)	3 Months Ended
	Mar. 31, 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: March 31, 2024 December 31, 2023 Product inventory $ 40.4 $ 46.4 Prepaid expenses and other 23.3 19.0 Other current assets $ 63.7 $ 65.4 Other current liabilities: March 31, 2024 December 31, 2023 Accrued interest $ 63.6 $ 63.4 Accrued wages and benefits, including taxes 12.7 23.2 Accrued ad valorem taxes 12.1 33.3 Capital expenditure accruals 56.3 64.6 Short-term lease liability 32.7 28.2 Operating expense accruals 21.0 21.5 Accrued common unit repurchase 23.1 41.5 Other 26.4 2.8 Other current liabilities $ 247.9 $ 278.5

General (Details)

General (Details)	3 Months Ended
	Mar. 31, 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	5.8
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	45.80%

Significant Accounting Polici_3

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Mar. 31, 2024 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,712
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	9 months
Remaining performance obligations	$ 116.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 147.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 153.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 125.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 116.4
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period
Remaining performance obligations	$ 1,053

Significant Accounting Polici_4

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Property, Plant and Equipment [Line Items]
Impairment charges	$ 14.2	$ 0

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 31.8	$ 31.9
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)	20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Intangible asset, weighted average remaining amortization period	14 years 10 months 24 days

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 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	(31.8)	$ (31.9)
Gross carrying amount, ending balance	1,844.8
Accumulated amortization, ending balance	(1,083)
Net carrying amount, ending balance	$ 761.8

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
2024	$ 95.8
2025	110.2
2026	106.3
2027	106.3
2028	106.3
Thereafter	236.9
Total	$ 761.8	$ 793.6

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended
	Jan. 16, 2024	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Related Party Transaction [Line Items]
Accrued natural gas, NGLs, condensate, and crude oil purchases		$ 113		$ 126.5
Midstream services revenue		1,676.9	$ 1,755.6
Cost of sales		(1,150.4)	(1,271.9)
Repurchase Agreement Renewal Term	1 year
Midstream services revenue
Related Party Transaction [Line Items]
Midstream services revenue		271.9	279.3
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
Cost of sales		(1.4)	(1.5)
Product sales—related parties | Midstream services revenue | Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Midstream services revenue		$ 0.5	$ 0.7

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Debt Instrument
Outstanding Principal	$ 4,606.2	$ 4,609.2
Premium (Discount)	(8)	(8.2)
Long-Term Debt	4,598.2	4,601
Debt issuance costs	(30.8)	(32.1)
Less: Current maturities of long-term debt	(97.9)	(97.9)
Long-term debt, net of unamortized issuance cost	4,469.5	4,471
Debt issuance cost accumulated amortization	21.4	20
Revolving Credit Facility Due 2027
Debt Instrument
Outstanding Principal	150	0
Premium (Discount)	0	0
Long-Term Debt	$ 150	0
Effective interest rate (as a percent)	6.90%
AR Facility due 2025
Debt Instrument
Outstanding Principal	$ 147	300
Premium (Discount)	0	0
Long-Term Debt	$ 147	$ 300
Effective interest rate (as a percent)	6.30%	6.40%
4.40% Senior Notes due 2024
Debt Instrument
Outstanding Principal	$ 97.9	$ 97.9
Premium (Discount)	0	0
Long-Term Debt	$ 97.9	97.9
Stated interest rate (as a percent)	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding Principal	$ 421.6	421.6
Premium (Discount)	0	0
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)	(0.2)	(0.2)
Long-Term Debt	$ 490.8	490.8
Stated interest rate (as a percent)	4.85%
5.625% Senior unsecured notes due 2028
Debt Instrument
Outstanding Principal	$ 500	500
Premium (Discount)	0	0
Long-Term Debt	$ 500	500
Stated interest rate (as a percent)	5.625%
5.375% Senior Notes Due 2029
Debt Instrument
Outstanding Principal	$ 498.7	498.7
Premium (Discount)	0	0
Long-Term Debt	$ 498.7	498.7
Stated interest rate (as a percent)	5.375%
6.50% Senior Notes due 2030
Debt Instrument
Outstanding Principal	$ 1,000	1,000
Premium (Discount)	(2.6)	(2.7)
Long-Term Debt	$ 997.4	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	3 Months Ended
	Mar. 31, 2024 USD ($)
Debt Instrument
Increase (decrease) in accounts receivable	$ 497
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity	389.1
Accounts receivable securitization facility, outstanding amount	147
Letters of credit
Debt Instrument
Additional amount available (not to exceed)	1,400
Line of credit facility, fair value of amount outstanding	150
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	$ 22.3

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.2)	$ (0.1)
Deferred income tax benefit (expense)	4	(10.8)
Income tax benefit (expense)	3.8	(10.9)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax expense based on federal statutory tax rate	(2.2)	(14.5)
State income tax expense, net of federal benefit	(0.4)	(1.8)
Unit-based compensation	7.3	6.5
Other	(0.9)	(1.1)
Income tax benefit (expense)	$ 3.8	$ (10.9)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Deferred tax assets	$ 774	$ 758.3
Deferred tax assets, valuation allowance	1.2	1.2
Deferred tax liabilities	875.1	862.5
Net deferred tax liabilities	$ 101.1	$ 104.2

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative (Details) - EnLink Midstream Partners, LP - $ / shares	3 Months Ended
	Mar. 31, 2024	Dec. 31, 2023
Redemption of Series B Preferred Units
Partnership agreement
Preferred units, outstanding (in shares)	54,712,077	54,575,638
Preferred units, issued (in shares)	54,712,077	54,575,638
Price payable, overage (in dollars per unit)	$ 7.05
Repurchase of Series C Preferred Units
Partnership agreement
Preferred units, outstanding (in shares)	366,500
Preferred units, issued (in shares)	366,500

Certain Provisions of the ENL_4

Certain Provisions of the ENLK Partnership Agreement - Summary of Distribution (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended
	Sep. 15, 2023	Dec. 15, 2022	Jun. 14, 2024	Mar. 31, 2024	Mar. 14, 2024	Dec. 31, 2023	Jun. 14, 2023	Mar. 31, 2023	Mar. 14, 2023	Dec. 31, 2022
Redemption of Series B Preferred Units | Limited Partner
Partnership agreement
Distribution paid-in kind (in shares)				130,270		136,439		135,421		0
Cash distributions				$ 14.7		$ 15.3		$ 15.2		$ 17.3
Repurchase of Series C Preferred Units
Partnership agreement
Cash distributions					$ 9		$ 8.7		$ 8.4
Distribution rate per unit	0.26161%				9.749%		9.051%		8.846%
Redemption price (per unit)		$ 1,000
Variable floating rate percentage	4.11%	4.11%
Repurchase of Series C Preferred Units | Forecast
Partnership agreement
Cash distributions			$ 9.1
Distribution rate per unit			9.701%

Members' Equity - Board_s Autho

Members' Equity - Board’s Authorizations of the Common Unit Repurchase Program (Details) - USD ($) $ in Millions	Dec. 31, 2023	Nov. 30, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Repurchase program, amount authorized	$ 200		$ 200
Stock repurchase program increase		$ 50

Members' Equity - IP Repurchase

Members' Equity - IP Repurchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	5,447,442	4,444,415
Aggregate cost for common units	$ 68.6	$ 51.4
Excise tax on common unit repurchases	$ 0.2	$ 0
Public ENLC Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	2,166,805	2,207,305
Aggregate cost for common units	$ 26.9	$ 26.8
Average price of shares repurchased (in dollars per share)	$ 12.41	$ 12.14
ENCL Common Units Held by GIP
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	3,280,637	2,237,110
Aggregate cost for common units	$ 41.5	$ 24.6
Average price of shares repurchased (in dollars per share)	$ 12.66	$ 11.01

Members' Equity - Narrative (De

Members' Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	Apr. 29, 2024	Mar. 31, 2024	Mar. 31, 2023
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)		5,447,442	4,444,415
Aggregate cost for common units		$ 68.6	$ 51.4
Accrued common unit repurchase		$ 23.1
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	1,862,695
Aggregate cost for common units	$ 23.1
Average price of shares repurchased (in dollars per share)	$ 12.40

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Distributed earnings allocated to:
Total distributed earnings	$ 60.5	$ 59.5
Undistributed loss allocated to:
Total undistributed loss, basic	(46)	(1.3)
Total undistributed loss, diluted	(46)	(1.3)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	14.5	58.2
Total net income attributable to ENLC, diluted	$ 14.5	$ 58.2
Net income attributable to ENLC per unit:
Basic (in dollars per share)	$ 0.03	$ 0.12
Diluted (in dollars per share)	$ 0.03	$ 0.12
Unvested unit-based awards
Distributed earnings allocated to:
Total distributed earnings	$ 0.7	$ 0.9
Undistributed loss allocated to:
Total undistributed loss, basic	(0.6)	0
Total undistributed loss, diluted	(0.6)	0
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	0.1	0.9
Total net income attributable to ENLC, diluted	0.1	0.9
Common units
Distributed earnings allocated to:
Total distributed earnings	59.8	58.6
Undistributed loss allocated to:
Total undistributed loss, basic	(45.4)	(1.3)
Total undistributed loss, diluted	(45.4)	(1.3)
Net income attributable to ENLC allocated to:
Total net income attributable to ENLC, basic	14.4	57.3
Total net income attributable to ENLC, diluted	$ 14.4	$ 57.3

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in shares)	451.3	468.9
Dilutive effect of unvested restricted units (in shares)	2.9	4.4
Total weighted average diluted common units outstanding (in shares)	454.2	473.3

Members' Equity - Distributions

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

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Equity method investments
Contributions	$ 9.4	$ 49.7
Distributions	0	(0.1)
Equity in income (loss)	(0.8)	(0.1)
Total investment in unconsolidated affiliates	$ 159.8		$ 150.5
GCF
Equity method investments
Ownership interest	38.75%
Contributions	$ 9.4	6.2
Equity in income (loss)	$ (1.8)	(1.1)
Cedar Cove JV
Equity method investments
Ownership interest	30%
Distributions	$ 0	(0.1)
Equity in income (loss)	$ (0.7)	(0.6)
Matterhorn JV
Equity method investments
Ownership interest	15%
Contributions	$ 0	43.5
Equity in income (loss)	1.7	$ 1.6
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	151.8		143.2
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	52.1		44.5
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	(8)		(7.3)
EnLink Midstream Partners, LP | Matterhorn JV
Equity method investments
Total investment in unconsolidated affiliates	$ 107.7		$ 106

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Allocation
Total unit-based compensation expense	$ 5.6	$ 4
Amount of related income tax benefit recognized in net income	1.3	0.9
Cost of unit-based compensation charged to operating expense
Allocation
Total unit-based compensation expense	0.9	0.9
Cost of unit-based compensation charged to general and administrative expense
Allocation
Total unit-based compensation expense	$ 4.7	$ 3.1

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended
	Dec. 31, 2023	Feb. 29, 2024	Mar. 31, 2024	Mar. 31, 2023
Unvested unit-based awards
Number of Units
Unvested, beginning of period (in shares)			5,445,980
Granted (in shares)			1,343,217
Vested (in shares)			(2,309,954)
Forfeited (in shares)			(5,397)
Unvested, end of period (in shares)	5,445,980		4,473,846
Aggregate intrinsic value, end of period			$ 61
Weighted Average Grant-Date Fair Value
Unvested, beginning of period (in dollars per share)			$ 7.27
Granted (in dollars per share)			12.36
Vested (in dollars per share)			3.94
Forfeited (in dollars per share)			9.96
Unvested, end of period (in dollars per share)	$ 7.27		$ 10.51
Incentive unit award vesting period	3 years		3 years
Units withheld for payroll taxes (in shares)			680,384
Aggregate intrinsic value of units vested			$ 28.1	$ 27.1
Fair value of units vested			9.1	13.4
Unrecognized compensation cost related to non-vested restricted incentive units			$ 29.7
Unrecognized compensation costs, weighted average period for recognition (in years)			2 years 1 month 6 days
Performance units
Number of Units
Unvested, beginning of period (in shares)			2,236,744
Granted (in shares)			508,586
Vested (in shares)			(1,061,232)
Forfeited (in shares)			(39,052)
Unvested, end of period (in shares)	2,236,744		1,645,046
Aggregate intrinsic value, end of period			$ 22.4
Weighted Average Grant-Date Fair Value
Unvested, beginning of period (in dollars per share)			$ 6.37
Granted (in dollars per share)			12.92
Vested (in dollars per share)			4.77
Forfeited (in dollars per share)			11.84
Unvested, end of period (in dollars per share)	$ 6.37		$ 9.30
Units withheld for payroll taxes (in shares)			576,040
Aggregate intrinsic value of units vested			$ 19.2	22
Fair value of units vested			5.1	$ 8.1
Unrecognized compensation cost related to non-vested restricted incentive units			$ 13.4
Unrecognized compensation costs, weighted average period for recognition (in years)			2 years
Performance Units:
Beginning TSR Price (in dollars per share)		$ 12.92
Grant-date fair value (in dollars per share)		$ 12.74
Risk-free interest rate (as a percent)		4.46%
Volatility factor (as a percent)		41.51%
Performance units | Minimum
Performance Units:
Percent of units vesting (as a percent)			0%
Performance units | Maximum
Performance Units:
Percent of units vesting (as a percent)			200%

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) - USD ($)	Mar. 31, 2024	Jan. 31, 2023
Derivatives
Derivative, notional amount		$ 400,000,000
Interest income out of accumulated other comprehensive loss over the next twelve months	$ 4,300,000
Commodity swaps
Derivatives
Maximum loss if counterparties fail to perform	107,300,000
Possible reduction in maximum loss if counterparties fail to perform	$ 4,200,000

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2024		Mar. 31, 2023		Dec. 31, 2023
Derivatives
Tax benefit (expense)		$ (0.9)		$ 0.4
Unrealized gain (loss) on designated cash flow hedge	[1]	3	[2]	(1.2)	[3]
Fair value of derivative assets—current		90.6				$ 76.9
Fair value of derivative assets—long-term		21.5				27
Fair value of derivative liabilities—current		(98)				(62.7)
Fair value of derivative liabilities—long-term		(21.8)				(26.7)
Interest income		1.5		0.5
Interest rate swap
Derivatives
Change in fair value of interest rate swap		3.9		(1.6)
Tax benefit (expense)		(0.9)		0.4
Unrealized gain (loss) on designated cash flow hedge		3		$ (1.2)
Fair value of derivative assets—current		4.3				3.3
Fair value of derivative assets—long-term		0.5				0
Fair value of derivative liabilities—long-term		0				(2.4)
Net fair value of commodity derivatives		4.8				0.9
Commodity swaps
Derivatives
Fair value of derivative assets—current		86.3				73.6
Fair value of derivative assets—long-term		21				27
Fair value of derivative liabilities—current		(98)				(62.7)
Fair value of derivative liabilities—long-term		(21.8)				(24.3)
Net fair value of commodity derivatives		$ (12.5)				$ 13.6
[1] Includes tax expense of $0.9 million and a tax benefit of $0.4 million for the three months ended March 31, 2024 and 2023, respectively. Includes tax expense of $0.9 million for the three months ended March 31, 2024. Includes a tax benefit of $0.4 million for the three months ended March 31, 2023.

Derivatives - Components of Com

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Derivatives
Change in fair value of interest rate swap	$ (26.1)	$ (1.4)
Gain (loss) on derivative activity	(29)	11.9
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of interest rate swap	(26.1)	(1.4)
Realized gain (loss) on derivatives	(2.9)	13.3
Gain (loss) on derivative activity	$ (29)	$ 11.9

Derivatives - Commodity Swaps A

Derivatives - Commodity Swaps Additional Information (Details) - Commodity swaps gal in Millions, bbl in Millions, BTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($) BTU gal bbl	Dec. 31, 2023 USD ($)
Derivatives
Net fair value of commodity derivatives	$ (12.5)	$ 13.6
NGL | Short
Derivatives
Notional amount (in MMgasl or MMBLS) | gal	136.1
Net fair value of commodity derivatives	$ (16.3)
NGL | Long
Derivatives
Notional amount (in MMgasl or MMBLS) | gal	72.5
Net fair value of commodity derivatives	$ (2.1)
Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | BTU	143.1
Net fair value of commodity derivatives	$ 87.4
Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | BTU	119
Net fair value of commodity derivatives	$ (81.4)
Crude and Condensate | Short
Derivatives
Notional amount (in MMgasl or MMBLS) | bbl	7.2
Net fair value of commodity derivatives	$ (7.8)
Crude and Condensate | Long
Derivatives
Notional amount (in MMgasl or MMBLS) | bbl	0.9
Net fair value of commodity derivatives	$ 7.7

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Interest rate swap
Fair Value
Net fair value of commodity derivatives	$ 4.8	$ 0.9
Commodity derivatives
Fair Value
Net fair value of commodity derivatives	(12.5)	13.6
Level 2 | Interest rate swap | Recurring
Fair Value
Net fair value of commodity derivatives	4.8	0.9
Level 2 | Commodity derivatives | Recurring
Fair Value
Net fair value of commodity derivatives	$ (12.5)	$ 13.6

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023	Apr. 30, 2022
Fair Value
Debt issuance costs	$ 30.8		$ 32.1
Contingent Consideration, Liability [Roll Forward]
Fair Value, Liability, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	General and Administrative Expense
Contingent consideration, beginning balance	$ 6.7	$ 5.5
Change in fair value	1.7	0.7
Earnout payments	(2.5)	0
Contingent consideration, ending balance	$ 5.9	6.2
Amarillo Rattler, LLC
Contingent Consideration, Liability [Roll Forward]
Fair Value, Liability, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	General and Administrative Expense
Contingent consideration, beginning balance	$ 4.8	4.2
Change in fair value	1.4	0.5
Earnout payments	(2.3)	0
Contingent consideration, ending balance	$ 3.9	4.7
Business combination, maximum earnout				$ 15
Central Oklahoma Acquisition
Contingent Consideration, Liability [Roll Forward]
Fair Value, Liability, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	General and Administrative Expense
Contingent consideration, beginning balance	$ 1.9	1.3
Change in fair value	0.3	0.2
Earnout payments	(0.2)	0
Contingent consideration, ending balance	2	$ 1.5
Carrying Value
Fair Value
Long-term debt	4,567.4		4,568.9
Fair Value
Fair Value
Long-term debt	$ 4,424.8		$ 4,427

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended
	Mar. 31, 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
	Mar. 31, 2024	Mar. 31, 2023
Segment Reporting
Revenue from contracts with customers	$ 1,676.9	$ 1,755.6
Realized gain (loss) on derivatives	(2.9)	13.3
Change in fair value of derivatives	(26.1)	(1.4)
Total revenues	1,647.9	1,767.5
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,150.4)	(1,271.9)
Adjusted gross margin	497.5	495.6
Operating expenses	(152.6)	(132.4)
Segment profit	344.9	363.2
Depreciation and amortization	(165.3)	(160.4)
Gross margin	179.6	202.8
Impairments	(14.2)	0
Gain on disposition of assets	1.7	0.4
General and administrative	(55.2)	(29.5)
Interest expense, net of interest income	(65.4)	(68.5)
Loss from unconsolidated affiliate investments	(0.8)	(0.1)
Other income	0.5	0
Income before non-controlling interest and income taxes	46.2	105.1
Capital expenditures	103.4	114.1
Permian
Segment Reporting
Revenue from contracts with customers	754.2	598.9
Realized gain (loss) on derivatives	(6.8)	(4)
Change in fair value of derivatives	(2.4)	6.3
Total revenues	745	601.2
Cost of sales, exclusive of operating expenses and depreciation and amortization	(582.1)	(457.1)
Adjusted gross margin	162.9	144.1
Operating expenses	(73.9)	(48.1)
Segment profit	89	96
Depreciation and amortization	(43.6)	(40)
Gross margin	45.4	56
Impairments	0
Gain on disposition of assets	0	0
General and administrative	0	0
Interest expense, net of interest income	0	0
Loss from unconsolidated affiliate investments	0	0
Other income	0
Income before non-controlling interest and income taxes	45.4	56
Capital expenditures	48.6	56.7
Louisiana
Segment Reporting
Revenue from contracts with customers	939.8	1,105.7
Realized gain (loss) on derivatives	6.4	7.2
Change in fair value of derivatives	(19.5)	(9)
Total revenues	926.7	1,103.9
Cost of sales, exclusive of operating expenses and depreciation and amortization	(789.5)	(973.9)
Adjusted gross margin	137.2	130
Operating expenses	(26.8)	(33.6)
Segment profit	110.4	96.4
Depreciation and amortization	(35.1)	(38.3)
Gross margin	75.3	58.1
Impairments	0
Gain on disposition of assets	1.7	0.1
General and administrative	0	0
Interest expense, net of interest income	0	0
Loss from unconsolidated affiliate investments	0	0
Other income	0
Income before non-controlling interest and income taxes	77	58.2
Capital expenditures	31.6	12.3
Oklahoma
Segment Reporting
Revenue from contracts with customers	264.6	312.8
Realized gain (loss) on derivatives	(1)	2
Change in fair value of derivatives	(4.1)	(1.4)
Total revenues	259.5	313.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(147.8)	(194)
Adjusted gross margin	111.7	119.4
Operating expenses	(26)	(24.7)
Segment profit	85.7	94.7
Depreciation and amortization	(56.5)	(51.9)
Gross margin	29.2	42.8
Impairments	0
Gain on disposition of assets	0	0.2
General and administrative	0	0
Interest expense, net of interest income	0	0
Loss from unconsolidated affiliate investments	0	0
Other income	0
Income before non-controlling interest and income taxes	29.2	43
Capital expenditures	11.8	25.7
North Texas
Segment Reporting
Revenue from contracts with customers	168.6	180.9
Realized gain (loss) on derivatives	(1.5)	8.1
Change in fair value of derivatives	(0.1)	2.7
Total revenues	167	191.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	(81.3)	(89.6)
Adjusted gross margin	85.7	102.1
Operating expenses	(25.9)	(26)
Segment profit	59.8	76.1
Depreciation and amortization	(28.5)	(28.8)
Gross margin	31.3	47.3
Impairments	(14.2)
Gain on disposition of assets	0	0.1
General and administrative	0	0
Interest expense, net of interest income	0	0
Loss from unconsolidated affiliate investments	0	0
Other income	0
Income before non-controlling interest and income taxes	17.1	47.4
Capital expenditures	10.5	18.1
Corporate
Segment Reporting
Revenue from contracts with customers	(450.3)	(442.7)
Realized gain (loss) on derivatives	0	0
Change in fair value of derivatives	0	0
Total revenues	(450.3)	(442.7)
Cost of sales, exclusive of operating expenses and depreciation and amortization	450.3	442.7
Adjusted gross margin	0	0
Operating expenses	0	0
Segment profit	0	0
Depreciation and amortization	(1.6)	(1.4)
Gross margin	(1.6)	(1.4)
Impairments	0
Gain on disposition of assets	0	0
General and administrative	(55.2)	(29.5)
Interest expense, net of interest income	(65.4)	(68.5)
Loss from unconsolidated affiliate investments	(0.8)	(0.1)
Other income	0.5
Income before non-controlling interest and income taxes	(122.5)	(99.5)
Capital expenditures	0.9	1.3
Product sales
Segment Reporting
Revenue from contracts with customers	1,405	1,476.3
Product sales | Permian
Segment Reporting
Revenue from contracts with customers	434.2	316.4
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers	887.7	1,046.3
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	62.7	100.1
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers	20.4	13.5
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Natural gas sales
Segment Reporting
Revenue from contracts with customers	281.5	342.4
Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers	104.2	129.3
Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers	119.6	131.8
Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	32.8	66.8
Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers	24.9	14.5
Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
NGL sales
Segment Reporting
Revenue from contracts with customers	755.7	865.9
NGL sales | Permian
Segment Reporting
Revenue from contracts with customers	(6.6)	0.4
NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers	768.1	857.9
NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	(1)	8.6
NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers	(4.8)	(1)
NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers	367.5	268
Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers	336.6	186.7
Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers	0	56.6
Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	30.9	24.7
Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers	0	0
Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Other
Segment Reporting
Revenue from contracts with customers	0.3
Other | Permian
Segment Reporting
Revenue from contracts with customers	0
Other | Louisiana
Segment Reporting
Revenue from contracts with customers	0
Other | Oklahoma
Segment Reporting
Revenue from contracts with customers	0
Other | North Texas
Segment Reporting
Revenue from contracts with customers	0.3
Other | Corporate
Segment Reporting
Revenue from contracts with customers	0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	257.6	237.5
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	9.6	4.4
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	108.7	118
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	73.9	82.2
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(449.8)	(442.1)
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
NGL sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	257.6	237.5
NGL sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	9.5	4.4
NGL sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	108.7	118
NGL sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	70.6	79.5
NGL sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(446.4)	(439.4)
Crude oil and condensate sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Crude oil and condensate sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0	0
Crude oil and condensate sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0
Crude oil and condensate sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0
Crude oil and condensate sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	3.3	2.7
Crude oil and condensate sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(3.3)	(2.7)
Midstream services
Segment Reporting
Revenue from contracts with customers	271.9	279.3
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers	62.4	45
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers	42.5	55
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers	93.2	94.7
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers	73.8	84.6
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Gathering and transportation
Segment Reporting
Revenue from contracts with customers	165.5	150.2
Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers	39.7	23.3
Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers	24.4	20
Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers	55.8	54.8
Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers	45.6	52.1
Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Processing
Segment Reporting
Revenue from contracts with customers	78.8	81.7
Processing | Permian
Segment Reporting
Revenue from contracts with customers	17	14
Processing | Louisiana
Segment Reporting
Revenue from contracts with customers	0.6	0.3
Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers	33.6	35.3
Processing | North Texas
Segment Reporting
Revenue from contracts with customers	27.6	32.1
Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
NGL services
Segment Reporting
Revenue from contracts with customers	17.4	27.8
NGL services | Permian
Segment Reporting
Revenue from contracts with customers	0	0
NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers	17.3	27.8
NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0
NGL services | North Texas
Segment Reporting
Revenue from contracts with customers	0.1	0
NGL services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Crude services
Segment Reporting
Revenue from contracts with customers	7.8	17.2
Crude services | Permian
Segment Reporting
Revenue from contracts with customers	3.8	6
Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers	0.1	6.5
Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers	3.7	4.5
Crude services | North Texas
Segment Reporting
Revenue from contracts with customers	0.2	0.2
Crude services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Other services
Segment Reporting
Revenue from contracts with customers	2.4	2.4
Other services | Permian
Segment Reporting
Revenue from contracts with customers	1.9	1.7
Other services | Louisiana
Segment Reporting
Revenue from contracts with customers	0.1	0.4
Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.1
Other services | North Texas
Segment Reporting
Revenue from contracts with customers	0.3	0.2
Other services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	0.5	0.6
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(0.5)	(0.6)
NGL services—related parties
Segment Reporting
Revenue from contracts with customers	0	0
NGL services—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0	0
NGL services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0
NGL services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0
NGL services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	0.5	0.6
NGL services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	$ (0.5)	$ (0.6)

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Segment Reporting
Total identifiable assets	$ 8,128	$ 8,328.6
Permian
Segment Reporting
Total identifiable assets	2,784.9	2,813.6
Louisiana
Segment Reporting
Total identifiable assets	1,963.8	2,031.8
Oklahoma
Segment Reporting
Total identifiable assets	2,214	2,275.8
North Texas
Segment Reporting
Total identifiable assets	962.6	1,017.7
Corporate
Segment Reporting
Total identifiable assets	$ 202.7	$ 189.7

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Other current assets:
Product inventory	$ 40.4	$ 46.4
Prepaid expenses and other	23.3	19
Other current assets	63.7	65.4
Other current liabilities:
Accrued interest	63.6	63.4
Accrued wages and benefits, including taxes	12.7	23.2
Accrued ad valorem taxes	12.1	33.3
Capital expenditure accruals	56.3	64.6
Short-term lease liability	32.7	28.2
Operating expense accruals	21	21.5
Accrued common unit repurchase	23.1	41.5
Other	26.4	2.8
Other current liabilities	$ 247.9	$ 278.5

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) - Harris County Multi-District Litigation - EnLink Energy GP, LLC	3 Months Ended
	Mar. 31, 2024 claim defendant
Commitments and Contingencies
Number of defendants | defendant	350
Filed cases, over	150
Third party claims, number	90