EnLink Midstream (ENLC) 10-K 21 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2023	Feb. 14, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
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.,
Entity Address, Address Line Two	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 LimitedLiability Company Interests
Trading Symbol	ENLC
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 2.6
Entity Common Stock, Shares Outstanding		453,176,911
Documents Incorporated by Reference	None.
Document Fiscal Year Focus	2023
Amendment Flag	false
Entity Central Index Key	0001592000
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Firm ID	185
Auditor Location	Dallas, TX
Auditor Name	KPMG LLP

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents		$ 28.7	$ 22.6
Accounts receivable:
Trade receivables	[1]	85.9	89.2
Accrued revenue and other		581.4	636
Fair value of derivative assets		76.9	68.4
Other current assets		65.4	166.6
Total current assets		838.3	982.8
Property and equipment, net of accumulated depreciation of $5,137.2 and $4,774.5, respectively		6,407	6,556
Intangible assets, net of accumulated amortization of $1,051.2 and $923.6, respectively		793.6	921.2
Investment in unconsolidated affiliates		150.5	90.2
Fair value of derivative assets		27	2.9
Other assets, net		112.2	97.9
Total assets		8,328.6	8,651
Current liabilities:
Accounts payable and drafts payable		126.5	126.9
Accrued natural gas, NGLs, condensate, and crude oil purchases		428	476
Fair value of derivative liabilities		62.7	42.9
Current maturities of long-term debt		97.9	0
Other current liabilities		278.5	229.6
Total current liabilities		993.6	875.4
Long-term debt, net of unamortized issuance cost		4,471	4,723.5
Other long-term liabilities		98	94
Deferred tax liability, net		104.2	42.7
Fair value of derivative liabilities		26.7	2.7
Members’ equity:
Members’ equity (451,614,086 and 468,980,630 units issued and outstanding, respectively)		1,000.5	1,306.4
Accumulated other comprehensive income		0.7	0
Non-controlling interest		1,633.9	1,606.3
Total members’ equity		2,635.1	2,912.7
Commitments and contingencies (Note 15)
Total liabilities and members’ equity		$ 8,328.6	$ 8,651
[1] There was no allowance for bad debt at December 31, 2023. Includes allowance for bad debt of $0.1 million at December 31, 2022.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
ASSETS
Property and equipment, net of accumulated depreciation of $5,137.2 and $4,774.5, respectively	$ 5,137.2	$ 4,774.5
Intangible assets, net of accumulated amortization of $1,051.2 and $923.6, respectively	$ 1,051.2	$ 923.6
Members’ equity:
Common units issued (in shares)	451,614,086	468,980,630
Common units outstanding (in shares)	451,614,086	468,980,630
Allowance for bad debt	$ 0	$ 0.1

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Revenue from contracts with customers	$ 6,879.4	$ 9,527.8	$ 6,845
Gain (loss) on derivative activity	20.7	14.3	(159.1)
Total revenues	6,900.1	9,542.1	6,685.9
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	4,856.1	7,572.8	5,189.9
Operating expenses	558.2	524.9	362.9
Depreciation and amortization	657.1	639.4	607.5
Impairments	20.7	0	0.8
(Gain) loss on disposition of assets	(0.3)	18	(1.5)
General and administrative	115.5	125.2	107.8
Total operating costs and expenses	6,207.3	8,880.3	6,267.4
Operating income	692.8	661.8	418.5
Other income (expense):
Interest expense, net of interest income	(271.7)	(245)	(238.7)
Loss on extinguishment of debt	0	(6.2)	0
Loss from unconsolidated affiliate investments	(8.2)	(5.6)	(11.5)
Other income (expense)	(0.1)	0.8	0
Total other expense	(280)	(256)	(250.2)
Income before non-controlling interest and income taxes	412.8	405.8	168.3
Income tax benefit (expense)	(62.8)	94.9	(25.4)
Net income	350	500.7	142.9
Net income attributable to non-controlling interest	143.8	139.4	120.5
Net income attributable to ENLC	$ 206.2	$ 361.3	$ 22.4
Net income attributable to ENLC per unit:
Basic common unit (in dollars per share)	$ 0.45	$ 0.76	$ 0.05
Diluted common unit (in dollars per share)	$ 0.44	$ 0.74	$ 0.05
Product sales
Revenues:
Revenue from contracts with customers	$ 5,755.6	$ 8,564.9	$ 5,994
Midstream services
Revenues:
Revenue from contracts with customers	$ 1,123.8	$ 962.9	$ 851

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income		$ 350		$ 500.7		$ 142.9
Unrealized gain on designated cash flow hedge	[1]	0.7	[2]	1.4	[3]	13.9	[4]
Comprehensive income		350.7		502.1		156.8
Comprehensive income attributable to non-controlling interest		143.8		139.4		120.5
Comprehensive income attributable to ENLC		$ 206.9		$ 362.7		$ 36.3
[1] Includes tax expense of $0.2 million, $0.5 million, and $4.3 million for the years ended December 31, 2023, 2022, and 2021, respectively. Includes tax expense of $0.2 million. Includes tax expense of $0.5 million. Includes tax expense of $4.3 million.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Tax expense	$ (0.2)	$ (0.5)	$ (4.3)

Consolidated Statements of Chan

Consolidated Statements of Changes in Members' Equity - USD ($) $ in Millions		Total		Series B Preferred Units	Series C Preferred Units	Common Units	Accumulated Other Comprehensive Income (Loss)	Non-Controlling Interest	Non-Controlling Interest Series B Preferred Units	Non-Controlling Interest Series C Preferred Units	Redeemable Non-controlling interest (Temporary Equity)
Member equity, beginning balance at Dec. 31, 2020		$ 3,213				$ 1,508.8	$ (15.3)	$ 1,719.5
Units outstanding, beginning balance (in shares) at Dec. 31, 2020						489,400,000
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(2)				$ (2)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)						1,000,000
Unit-based compensation		23.6				$ 23.6
Contributions from non-controlling interests		3.2						3.2
Distributions		(317.4)				(186.8)		(130.6)			$ (0.2)
Unrealized gain on designated cash flow hedge	[2]	13.9	[1]				13.9
Fair value adjustment related to redeemable non-controlling interest / Adjustment related to the redemption of the mandatorily redeemable non-controlling interest		(0.1)									0.2
Redemption and repurchase of preferred units				$ (50)					$ (50)
Common units repurchased		$ (40.1)				$ (40.1)
Common units repurchased (in shares)		(6,091,001)				(6,100,000)
Net income		$ 142.9				$ 22.4		120.5
Member equity, end balance at Dec. 31, 2021		2,987				$ 1,325.8	(1.4)	1,662.6
Units outstanding, end balance (in shares) at Dec. 31, 2021						484,300,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2020											0
Increase (Decrease) in Temporary Equity
Distributions		(317.4)				$ (186.8)		(130.6)			(0.2)
Fair value adjustment related to redeemable non-controlling interest		(0.1)									0.2
Redeemable noncontrolling interest, ending balance at Dec. 31, 2021											0
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(16.1)				$ (16.1)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)						3,100,000
Unit-based compensation		31.8				$ 31.8
Contributions from non-controlling interests		32.9						32.9
Distributions		(384.3)				(221.4)		(162.9)			0
Unrealized gain on designated cash flow hedge	[3]	1.4	[1]				1.4
Redemption and repurchase of preferred units				$ (50.5)	$ (15.2)				$ (50.5)	$ (15.2)
Common units repurchased		$ (175)				$ (175)
Common units repurchased (in shares)		(18,374,054)				(18,400,000)
Net income		$ 500.7				$ 361.3		139.4
Member equity, end balance at Dec. 31, 2022		$ 2,912.7				$ 1,306.4	0	1,606.3
Units outstanding, end balance (in shares) at Dec. 31, 2022		468,980,630				469,000,000
Increase (Decrease) in Temporary Equity
Distributions		$ (384.3)				$ (221.4)		(162.9)			0
Redeemable noncontrolling interest, ending balance at Dec. 31, 2022											$ 0
Increase (Decrease) in Members' Equity
Conversion of unit-based awards for common units, net of units withheld for taxes		(19.6)				$ (19.6)
Conversion of unit-based awards for common units, net of units withheld for taxes (in shares)						3,000,000
Unit-based compensation		19.2				$ 19.2
Contributions from non-controlling interests		69.5						69.5
Distributions		(408.8)				(236.2)		(172.6)
Unrealized gain on designated cash flow hedge	[4]	0.7	[1]				0.7
Redemption and repurchase of preferred units					$ (13.1)					$ (13.1)
Common units repurchased		$ (234.8)				$ (234.8)
Common units repurchased (in shares)		(20,377,407)				(20,400,000)
Accrued common unit repurchase	[5]	$ (41.5)				$ (41.5)
Net income		350				206.2		143.8
Member equity, end balance at Dec. 31, 2023		$ 2,635.1				$ 1,000.5	$ 0.7	1,633.9
Units outstanding, end balance (in shares) at Dec. 31, 2023		451,614,086				451,600,000
Increase (Decrease) in Temporary Equity
Distributions		$ (408.8)				$ (236.2)		$ (172.6)
[1] Includes tax expense of $0.2 million, $0.5 million, and $4.3 million for the years ended December 31, 2023, 2022, and 2021, respectively. Includes tax expense of $4.3 million. Includes tax expense of $0.5 million. Includes tax expense of $0.2 million. 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. As of December 31, 2023, we accrued $41.5 million in connection with the repurchase of ENLC common units held by GIP. For additional information, see “Note 10—Members’ Equity.”

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Members' Equity (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Statement of Stockholders' Equity [Abstract]
Income tax expense	$ 0.2
Amount accrued in connection with the repurchase of ENLC common units held by GIP	$ 41.5

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net income	$ 350	$ 500.7	$ 142.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	657.1	639.4	607.5
(Gain) loss on disposition of assets	(0.3)	18	(1.5)
Non-cash unit-based compensation	19.2	30.4	25.3
Utility credits redeemed (earned)	1.5	31.1	(32.6)
Non-cash (gain) loss on derivatives recognized in net income	12.1	(38.3)	10.3
Loss on extinguishment of debt	0	6.2	0
Amortization of debt issuance costs and net discount of senior unsecured notes	6.4	5.5	5.2
Amortization of designated cash flow hedge	0	1.9	12.5
Deferred income tax expense (benefit)	62.1	(95.3)	24.6
Loss from unconsolidated affiliate investments	8.2	5.6	11.5
Impairments	20.7	0	0.8
Other operating activities	1.5	(4.3)	(4)
Changes in assets and liabilities, net of the effects of acquisitions:
Accounts receivable, accrued revenue, and other	58.2	102.4	(259.9)
Product inventory, prepaid expenses, and other	97	(115)	(13.6)
Accounts payable, accrued product purchases, and other accrued liabilities	(71)	(39)	328.3
Net cash provided by operating activities	1,222.7	1,049.3	857.3
Cash flows from investing activities:
Additions to property and equipment	(445.7)	(332.5)	(184)
Acquisitions, net of cash acquired	0	(390.3)	(56.7)
Proceeds from disposition of assets	73.1	12.8	4.8
Contributions to unconsolidated affiliate investments	(68.1)	(65.9)	0
Other investing activities	0.2	2.9	4.5
Net cash used in investing activities	(440.5)	(773)	(231.4)
Cash flows from financing activities:
Proceeds from borrowings	2,843.4	4,911.5	1,234.5
Repayments on borrowings	(3,001.4)	(4,549.3)	(1,469.5)
Payment of installment payable for the Amarillo Rattler Acquisition	0	(10)	0
Payment of inactive easement commitment	0	(10)	0
Distributions to members	(236.2)	(221.4)	(186.8)
Distributions to non-controlling interests	(172.6)	(162.9)	(130.8)
Payment to redeem mandatorily redeemable non-controlling interest	(10.5)	0	0
Contributions from non-controlling interests	69.5	32.9	3.2
Common unit repurchases	(234.8)	(175)	(40.1)
Conversion of unit-based awards for common units, net of units withheld for taxes	(19.6)	(16.1)	(2)
Other financing activities	(0.8)	(13.9)	2.2
Net cash used in financing activities	(776.1)	(279.9)	(639.3)
Net increase (decrease) in cash and cash equivalents	6.1	(3.6)	(13.4)
Cash and cash equivalents, beginning of period	22.6	26.2	39.6
Cash and cash equivalents, end of period	28.7	22.6	26.2
Series B Preferred Units
Cash flows from financing activities:
Redemption and repurchase of preferred units	0	(50.5)	(50)
Series C Preferred Units
Cash flows from financing activities:
Redemption and repurchase of preferred units	$ (13.1)	$ (15.2)	$ 0

Organization and Nature of Busi

Organization and Nature of Business	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Business	(1) Organization and Nature of Business (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 December 31, 2023, GIP, through GIP III Stetson I, L.P. and GIP III Stetson II, L.P, owns 46.2% 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 the equity interests in the Managing Member. ENLC owns all of ENLK’s common units and also owns all of the membership interests of the General Partner. The General Partner manages ENLK’s operations and activities. (b) Nature of Business We primarily focus on providing midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, storing, trans-loading, and selling crude oil and condensate. As of December 31, 2023, our midstream energy asset 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.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. 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. (b) Management’s Use of Estimates The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. (c) Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows: • Product sales— Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above. • Midstream services— Midstream services represent all other revenue generated as a result of performing our midstream services outlined above. Evaluation of Our Contractual Performance Obligations Performance obligations in our contracts with customers include: • promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and • promises to sell a specified volume of commodities to our customers. The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Accounting Methodology for Certain Contracts For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of the commodities purchased. We account for the contractually-stated fees on the consolidated statements of operations as a reduction of cost of sales of such commodities purchased upon receipt of the raw mix NGLs, because we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased. For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under as outlined above for NGL contracts. For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories: • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased, net of fees. • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations. For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our natural gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Satisfaction of Performance Obligations and Recognition of Revenue For our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. We recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. Prior to issuing our financial statements, we review our revenue and purchases estimates based on available information to determine if adjustments are required. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). Minimum Volume Commitments and Firm Transportation Contracts The following table summarizes the contractually committed fees (in millions) that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods. Contractually Committed Fees Commitments 2024 $ 145.0 2025 126.2 2026 126.6 2027 105.9 2028 97.1 Thereafter 1,032.9 Total $ 1,633.7 (d) Imbalance Accounting Quantities of natural gas, NGLs, or crude and condensate over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas, NGLs, or crude and condensate. We had imbalance payables of $6.3 million and $17.3 million at December 31, 2023 and 2022, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $8.0 million and $20.2 million at December 31, 2023 and 2022, respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued revenue and other” and “Accrued natural gas, NGLs, condensate, and crude oil purchases,” respectively, on the consolidated balance sheets. (e) Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. (f) Income Taxes Certain of our operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of our operations are subject to tax assessed by the state of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas franchise tax is presented as income tax expense in the accompanying statements of operations. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. We record deferred tax assets and liabilities on a net basis on the consolidated balance sheets, with deferred tax assets included in “Other assets, net” and deferred tax liabilities included in “Deferred tax liability, net.” (g) Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory Our inventories of products consist of natural gas, NGLs, crude oil, and condensate. We report these assets at the lower of cost or market value which is determined by using the weighted average cost method. (h) Property and Equipment Property and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value. Routine repairs and maintenance are charged against income when incurred. Renewals and improvements that extend the useful life or improve the function of the properties are capitalized. The components of property and equipment, net of accumulated depreciation are as follows (in millions): Year Ended December 31, 2023 2022 Transmission assets $ 1,459.5 $ 1,452.0 Gathering systems 5,472.4 5,370.0 Natural gas processing plants and fractionation facilities 4,279.1 4,237.8 Other property and equipment 90.1 165.0 Construction in process 243.1 105.7 Property and equipment 11,544.2 11,330.5 Accumulated depreciation (5,137.2) (4,774.5) Property and equipment, net of accumulated depreciation $ 6,407.0 $ 6,556.0 Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Natural gas processing plants and fractionation facilities 20 - 25 years Other property and equipment 3 - 25 years Gain or Loss on Disposition. Upon the disposition or retirement of property and equipment, any gain or loss is recognized in operating income in the consolidated statements of operations. For the years ended December 31, 2023, 2022, and 2021, dispositions primarily related to the sale of certain non-core assets. The (gain) loss on disposition of assets is as follows (in millions): Year Ended December 31, 2023 2022 2021 Net book value of assets disposed $ 72.9 $ 30.8 $ 3.3 Proceeds from sales (73.1) (12.8) (4.8) Insurance recoveries (0.1) — — (Gain) loss on disposition of assets $ (0.3) $ 18.0 $ (1.5) Impairment Review . 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. When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding: • the future fee-based rate of new business or contract renewals; • the purchase and resale margins on natural gas, NGLs, crude oil, and condensate; • the volume of natural gas, NGLs, crude oil, and condensate available to the asset; • markets available to the asset; • operating expenses; and • future natural gas, NGLs, crude oil, and condensate prices. The estimated volume of natural gas, NGLs, crude oil, and condensate available to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil, and condensate prices. Projections of natural gas, NGL, crude oil, and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: • changes in general economic conditions or demand for our products in regions in which our markets are located; • the availability and prices of natural gas, NGLs, crude oil, and condensate supply; • our ability to negotiate favorable sales agreements; • the risks that natural gas, NGLs, crude oil, and condensate exploration and production activities will not occur or be successful; • our dependence on certain key customers, producers, and transporters of natural gas, NGLs, crude oil, and condensate; and • competition from other midstream companies, including major energy companies. We recognized impairment expense related to property and equipment as follows (in millions): Year Ended December 31, 2023 2022 2021 Property and equipment impairment (1) $ 20.7 $ — $ 0.6 ____________________________ (1) During the third quarter of 2023, we identified changes in our outlook for future cash flows and the anticipated use of certain ORV crude assets in our Louisiana segment. We determined that the carrying amounts of these assets exceeded their fair values, based on market inputs and certain assumptions. (i) Comprehensive Income (Loss) Comprehensive income (loss) is comprised of net income (loss) and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815. For additional information about the effect of financial instruments on comprehensive income (loss), see “Note 13—Derivatives.” (j) Equity Method of Accounting We account for investments where we do not control the investment but have the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. We recognize impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations. For additional information, see “Note 11—Investment in Unconsolidated Affiliates.” (k) Non-controlling Interests We account for investments where we control the investment using the consolidation method of accounting. Under this method, we consolidate all the assets and liabilities of an investment on our consolidated balance sheets and record non-controlling interest for the portion of the investment that we do not own. We include all of an investment’s results of operations on our consolidated statements of operations and record income attributable to non-controlling interests for the portion of the investment that we do not own. Our non-controlling interests for the years ended December 31, 2023, 2022, and 2021 are comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50.0% share of the Ascension JV. Certain of our joint venture arrangements provide our joint venture partners with the right, under certain circumstances, to cause us to purchase their interest in the joint venture or to seek to sell the entire joint venture. For example, at any time after June 30, 2025, NGP has the right to cause the Delaware Basin JV to sell all of the outstanding interests or assets of the Delaware Basin JV for the best available price; provided that, if NGP exercises this right, we are permitted to purchase NGP’s interest at a certain call price. (l) 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 range from ten Intangibles—Goodwill and Other , we evaluate intangibles for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. For additional information regarding our intangible assets, including our assessment of intangible assets for impairment, see “Note 4—Intangible Assets.” (m) Asset Retirement Obligations We recognize liabilities for retirement obligations associated with our assets. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Our retirement obligations include estimated environmental remediation costs that arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight-line depreciation method similar to that used for the associated property and equipment. (n) Leases We account for leases under ASC 842 whereby we recognized leases on our consolidated balance sheet by recording a right-of-use asset and lease liability. We evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. For more information, see “Note 6—Leases.” (o) Derivatives We use derivative instruments to hedge against changes in cash flows related to product price. We generally determine the fair value of swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet at the fair value of derivative assets or liabilities in accordance with ASC 815. Changes in fair value of derivative instruments are recorded in gain or loss on derivative activity in the period of change. Realized gains and losses on commodity-related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statements of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities. We periodically enter into interest rate swaps to hedge variability in interest rates and effectively lock in the benchmark interest rate at the inception of the swap. The change in fair value of interest rate swaps is recorded net as a gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). For additional information, see “Note 13—Derivatives.” (p) Concentrations of Credit Risk Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than our exposure to key customers discussed below, since our customers represent a broad and diverse group of energy marketers and end-users. The following customers individually represented greater than 10% of our consolidated revenues for the years ended December 31, 2023, 2022, or 2021. No other customers represented greater than 10% of our consolidated revenues during the periods presented. Year Ended December 31, 2023 2022 2021 Dow Hydrocarbons and Resources LLC 10.4 % 14.2 % 14.5 % Marathon Petroleum Corporation 19.3 % 14.7 % 13.4 % We continually monitor and review the credit exposure of our counterparties based on various credit quality indicators and metrics. We obtain letters of credit or other appropriate security when considered necessary to limit the risk of loss. We record reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers and we do not expect to experience significant levels of default on our trade accounts receivable. As of December 31, 2023, we had no reserve for uncollectible receivables. For the year ended December 31, 2022, we had a $0.1 million reserve for uncollectible receivables. (q) Environmental Costs Environmental expenditures are expensed or capitalized depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Environmental expenditures were not material for the years ended December 31, 2023, 2022, and 2021. (r) Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with a loss contingency are expensed as incurred. For additional information, see “Note 15—Commitments and Contingencies.” (s) Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized into interest expense using the straight-line method over the term of the related debt. Gains or losses on debt repurchases, redemptions, and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $32.1 million and $34.9 million as of December 31, 2023 and 2022, respectively, are included in “Long-term debt” on the consolidated balance sheets as a direct reduction from the carrying amount of the debt. (t) Redeemable Non-Controlling Interest Non-controlling interests that contain an option for the non-controlling interest holder to require us to purchase such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interests are not considered to be a component of members’ equity and are reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions). When the redemption feature is exercised the redemption value of the non-controlling interest is reclassified to a liability on the consolidated balance sheets. During the first quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. At the time of the exercise, we and the interest holder did not agree on the value of the interest and a lawsuit was filed by the interest holder. As part of a settlement effected with the interest holder in January 2023, we settled the redemption of the mandatorily redeemable non-con

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Acquisitions and Divestiture	(3) Acquisitions and Divestitures Amarillo Rattler Acquisition On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. In connection with the purchase, we entered into an amended and restated natural gas gathering and processing agreement with Diamondback E&P LLC, strengthening our dedicated acreage position with that entity. We acquired the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10.0 million that was paid on April 30, 2022, and contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Under the acquisition method of accounting, the acquired assets of Amarillo Rattler, LLC have been recorded at their respective fair values as of the date of the acquisition. Determining the fair value of the assets of Amarillo Ratter, LLC requires judgment and certain assumptions to be made, particularly related to the valuation of acquired customer relationships. The inputs and assumptions related to the customer relationships are categorized as level 3 in the fair value hierarchy. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 50.6 Installment payable 10.0 Contingent consideration fair value (1) 6.9 Total consideration: $ 67.5 Purchase price allocation Assets acquired: Current assets (including $1.3 million in cash) $ 1.4 Property and equipment 16.3 Intangible assets 50.6 Other assets, net (2) 0.6 Liabilities assumed: Current liabilities (0.8) Other long-term liabilities (2) (0.6) Net assets acquired $ 67.5 ____________________________ (1) The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from the estimated fair values. (2) “Other assets, net” and “Other long-term liabilities” consist of the right-of-use asset and lease liability, respectively, recorded through the acquisition of Amarillo Rattler, LLC. Barnett Shale Acquisition On July 1, 2022, we completed the Barnett Shale Acquisition for a cash purchase price of $275.0 million plus working capital of $14.5 million. These assets include approximately 400 miles of lean and rich natural gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. We completed this acquisition to increase the scale of our North Texas assets and realize efficiencies by redeploying redundant assets to our other segments, including the Permian segment in the near-term and the CCS business in the future. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 289.5 Purchase price allocation Assets acquired: Current assets $ 17.3 Property and equipment 275.0 Liabilities assumed: Current liabilities (2.8) Net assets acquired $ 289.5 We incurred $0.4 million of transaction costs related to the Barnett Shale Acquisition for the year ended December 31, 2022. These costs are included in general and administrative costs in the accompanying consolidated statements of operations. For the period from July 1, 2022 through December 31, 2022, we recognized $39.6 million of revenue and $24.1 million of net income related to the assets acquired. Central Oklahoma Acquisition On December 19, 2022, we completed the Central Oklahoma Acquisition for a cash purchase price of $95.8 million plus working capital of $5.1 million and an earnout valued at $1.3 million as of December 31, 2022, which was calculated in accordance with ASC 820. The earnout 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. The acquired assets include approximately 900 miles of lean and rich natural gas gathering pipeline and two processing plants with 280 MMcf/d of total processing capacity. We completed this acquisition to increase the scale and efficiency of our Central Oklahoma assets. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 100.9 Contingent consideration 1.3 Total consideration $ 102.2 Purchase price allocation Assets acquired: Current assets $ 6.0 Property and equipment 97.1 Other assets, net (1) 0.9 Liabilities assumed: Current liabilities (1.4) Other long-term liabilities (1) (0.4) Net assets acquired $ 102.2 ____________________________ (1) “Other assets, net” and “Other long-term liabilities” consist of the right-of-use assets and lease liabilities, respectively, obtained through the Central Oklahoma Acquisition. We incurred $0.3 million and $0.5 million of transaction costs related to the Central Oklahoma Acquisition for the years ended December 31, 2023 and December 31, 2022, respectively. These costs are included in general and administrative costs in the accompanying consolidated statements of operations. For the period from December 19, 2022 through December 31, 2022, we recognized $1.7 million of revenue and $0.6 million of net income related to the assets acquired. Contingent Consideration. The following table represents our change in carrying value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities for the periods presented (in millions): Year Ended December 31, 2023 2022 2021 Amarillo Rattler Acquisition contingent consideration Contingent consideration liability, beginning of period $ 4.2 $ 6.9 $ — Contingent consideration liability recorded upon acquisition (1) — — 6.9 Change in fair value 0.6 (2.7) — Contingent consideration liability, end of period $ 4.8 $ 4.2 $ 6.9 Central Oklahoma Acquisition contingent consideration Contingent consideration liability, beginning of period $ 1.3 $ — $ — Contingent consideration liability recorded upon acquisition (2) — 1.3 — Change in fair value 0.6 — — Contingent consideration liability, end of period $ 1.9 $ 1.3 $ — Total contingent consideration Contingent consideration liability, beginning of period $ 5.5 $ 6.9 $ — Contingent consideration liability recorded upon acquisition (1)(2) — 1.3 6.9 Change in fair value 1.2 (2.7) — Contingent consideration liability, end of period $ 6.7 $ 5.5 $ 6.9 ____________________________ (1) The contingent consideration for the Amarillo Rattler Acquisition was recorded on April 30, 2021. (2) The contingent consideration for the Central Oklahoma Acquisition was recorded on December 19, 2022. Pro Forma of Acquisitions for the Years Ended December 31, 2022 and 2021 The following unaudited pro forma condensed consolidated financial information (in millions) for the years ended December 31, 2022 and 2021 gives effect to the Barnett Shale Acquisition on July 1, 2022 and the Central Oklahoma Acquisition on December 19, 2022 as if each of the acquisitions had occurred on January 1, 2021. On a historical pro forma basis, our consolidated revenues, net income (loss), total assets, and earnings per unit amounts would not have differed materially had the Amarillo Rattler Acquisition been completed on January 1, 2021 rather than April 30, 2021. The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Year Ended December 31, 2022 2021 Pro forma total revenues $ 9,630.4 $ 6,782.9 Pro forma net income $ 534.3 $ 157.5 ORV Divestitures On November 1, 2023, we sold certain ORV crude assets in our Louisiana segment to a subsidiary of Ergon, Inc. in exchange for cash consideration of approximately $59.2 million, subject to post-closing purchase price adjustments, and a contingent payment of an additional $0.5 million subject to the buyer’s pursuit of certain commercial opportunities within three years after the acquisition date.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	(4) Intangible Assets Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years. The following table represents our change in carrying value of intangible assets for the periods stated (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Year Ended December 31, 2023 Customer relationships, beginning of period $ 1,844.8 $ (923.6) $ 921.2 Amortization expense — (127.6) (127.6) Customer relationships, end of period $ 1,844.8 $ (1,051.2) $ 793.6 Year Ended December 31, 2022 Customer relationships, beginning of period $ 1,844.8 $ (795.1) $ 1,049.7 Amortization expense — (128.5) (128.5) Customer relationships, end of period $ 1,844.8 $ (923.6) $ 921.2 Year Ended December 31, 2021 Customer relationships, beginning of period $ 1,794.2 $ (668.8) $ 1,125.4 Customer relationships obtained from acquisition of business 50.6 — 50.6 Amortization expense — (126.3) (126.3) Customer relationships, end of period $ 1,844.8 $ (795.1) $ 1,049.7 The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2024 $ 127.6 2025 110.2 2026 106.3 2027 106.3 2028 106.3 Thereafter 236.9 Total $ 793.6

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Related Party Transactions	(5) Related Party Transactions (a) Transactions with the Cedar Cove JV We process natural gas and purchase the related residue 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: December 31, 2023 December 31, 2022 Accrued natural gas, NGLs, condensate, and crude oil purchases $ 0.3 $ 2.5 We recorded the following amounts (in millions) on our consolidated statements of operations related to our transactions with the Cedar Cove JV: Year Ended December 31, 2023 2022 2021 Midstream services revenue $ 2.5 $ 2.2 $ — Cost of sales (7.5) (28.2) (17.9) (b) Transactions with GIP In March 2022, our data center provider since 2009, CyrusOne Inc. (“CyrusOne”), was purchased by an entity that is owned collectively by funds affiliated with GIP and Kohlberg Kravis Roberts & Co. L.P. We paid CyrusOne $0.2 million in fees for data center services for each of the years ended December 31, 2023 and 2022. 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 10—Members’ Equity” for additional information on the activity related to the GIP repurchase agreement.

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	(6) Leases The majority of our leases are for the following types of assets: • Office space. Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represented $40.4 million of our lease liability and $20.7 million of our right-of-use asset as of December 31, 2023. Our office leases represented $46.2 million of our lease liability and $24.2 million of our right-of-use asset as of December 31, 2022. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred. • Compression and other field equipment. We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one right-of-use asset as of December 31, 2022. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred. • Land and land easements. We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represented $15.7 million of our lease liability and $12.4 million of our right-of-use asset as of December 31, 2023. Land and land easement leases represented $15.6 million of our lease liability and $12.3 million of our right-of-use asset as of December 31, 2022. Lease balances are recorded on the consolidated balance sheets as follows (in millions): Operating leases: December 31, 2023 December 31, 2022 Other assets, net $ 75.6 $ 69.5 Other current liabilities $ 28.2 $ 26.2 Other long-term liabilities $ 69.6 $ 66.2 Other lease information Weighted-average remaining lease term—Operating leases 7.7 years 8.7 years Weighted-average discount rate—Operating leases 5.3 % 4.7 % Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions. Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. Impairments of right-of-use assets are recognized in “Impairments” on the consolidated statements of operations. Sublease income is recognized as a reduction in “General and administrative,” “Operating expenses,” or as “Other income” depending on the nature of the subleased asset. The components of total lease expense are as follows (in millions): Year Ended December 31, 2023 2022 2021 Operating lease expense: Long-term operating lease expense $ 34.6 $ 28.2 $ 21.7 Short-term lease expense 41.3 34.3 17.5 Variable lease expense 18.6 18.8 15.6 Impairments — — 0.2 Total lease expense, before sublease income 94.5 81.3 55.0 Sublease income (1.8) (1.1) — Total lease expense, net of sublease income $ 92.7 $ 80.2 $ 55.0 Lease Maturities The following table summarizes the maturity of our lease liability as of December 31, 2023 (in millions): Total 2024 2025 2026 2027 2028 Thereafter Undiscounted operating lease liability $ 123.8 $ 31.8 $ 24.4 $ 15.2 $ 9.1 $ 8.7 $ 34.6 Reduction due to present value (26.0) (4.3) (3.2) (2.3) (1.8) (1.4) (13.0) Operating lease liability $ 97.8 $ 27.5 $ 21.2 $ 12.9 $ 7.3 $ 7.3 $ 21.6
Leases	(6) Leases The majority of our leases are for the following types of assets: • Office space. Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represented $40.4 million of our lease liability and $20.7 million of our right-of-use asset as of December 31, 2023. Our office leases represented $46.2 million of our lease liability and $24.2 million of our right-of-use asset as of December 31, 2022. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred. • Compression and other field equipment. We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one right-of-use asset as of December 31, 2022. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred. • Land and land easements. We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represented $15.7 million of our lease liability and $12.4 million of our right-of-use asset as of December 31, 2023. Land and land easement leases represented $15.6 million of our lease liability and $12.3 million of our right-of-use asset as of December 31, 2022. Lease balances are recorded on the consolidated balance sheets as follows (in millions): Operating leases: December 31, 2023 December 31, 2022 Other assets, net $ 75.6 $ 69.5 Other current liabilities $ 28.2 $ 26.2 Other long-term liabilities $ 69.6 $ 66.2 Other lease information Weighted-average remaining lease term—Operating leases 7.7 years 8.7 years Weighted-average discount rate—Operating leases 5.3 % 4.7 % Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions. Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. Impairments of right-of-use assets are recognized in “Impairments” on the consolidated statements of operations. Sublease income is recognized as a reduction in “General and administrative,” “Operating expenses,” or as “Other income” depending on the nature of the subleased asset. The components of total lease expense are as follows (in millions): Year Ended December 31, 2023 2022 2021 Operating lease expense: Long-term operating lease expense $ 34.6 $ 28.2 $ 21.7 Short-term lease expense 41.3 34.3 17.5 Variable lease expense 18.6 18.8 15.6 Impairments — — 0.2 Total lease expense, before sublease income 94.5 81.3 55.0 Sublease income (1.8) (1.1) — Total lease expense, net of sublease income $ 92.7 $ 80.2 $ 55.0 Lease Maturities The following table summarizes the maturity of our lease liability as of December 31, 2023 (in millions): Total 2024 2025 2026 2027 2028 Thereafter Undiscounted operating lease liability $ 123.8 $ 31.8 $ 24.4 $ 15.2 $ 9.1 $ 8.7 $ 34.6 Reduction due to present value (26.0) (4.3) (3.2) (2.3) (1.8) (1.4) (13.0) Operating lease liability $ 97.8 $ 27.5 $ 21.2 $ 12.9 $ 7.3 $ 7.3 $ 21.6

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Long-Term Debt	(7) Long-Term Debt As of December 31, 2023 and 2022, long-term debt consisted of the following (in millions): December 31, 2023 December 31, 2022 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt AR Facility due 2025 (1) 300.0 — 300.0 500.0 — 500.0 Revolving Credit Facility due 2027 (2) — — — 255.0 — 255.0 ENLK’s 4.40% Senior unsecured notes due 2024 97.9 — 97.9 97.9 — 97.9 ENLK’s 4.15% Senior unsecured notes due 2025 421.6 — 421.6 421.6 (0.1) 421.5 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.2) 490.8 491.0 (0.2) 490.8 ENLC’s 5.625% Senior unsecured notes due 2028 500.0 — 500.0 500.0 — 500.0 ENLC’s 5.375% Senior unsecured notes due 2029 498.7 — 498.7 498.7 — 498.7 ENLC’s 6.50% Senior unsecured notes due 2030 1,000.0 (2.7) 997.3 700.0 — 700.0 ENLK’s 5.60% Senior unsecured notes due 2044 350.0 (0.2) 349.8 350.0 (0.2) 349.8 ENLK’s 5.05% Senior unsecured notes due 2045 450.0 (5.0) 445.0 450.0 (5.2) 444.8 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,609.2 $ (8.2) 4,601.0 $ 4,764.2 $ (5.8) 4,758.4 Debt issuance cost (3) (32.1) (34.9) Less: Current maturities of long-term debt (4) (97.9) — Long-term debt, net of unamortized issuance cost $ 4,471.0 $ 4,723.5 ____________________________ (1) The effective interest rate was 6.4% and 5.3% at December 31, 2023 and 2022, respectively. (2) The effective interest rate was 6.5% at December 31, 2022. (3) Net of accumulated amortization of $20.0 million and $15.1 million at December 31, 2023 and 2022, respectively. (4) The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes as of December 31, 2023 are classified as “Current maturities of long-term debt” on the consolidated balance sheet as these notes mature on April 1, 2024. Maturities Maturities for the long-term debt as of December 31, 2023 are as follows (in millions): 2024 $ 97.9 2025 721.6 2026 491.0 2027 — 2028 500.0 Thereafter 2,798.7 Subtotal 4,609.2 Less: net discount (8.2) Less: debt issuance cost (32.1) Less: current maturities of long-term debt (97.9) Long-term debt, net of unamortized issuance cost $ 4,471.0 Revolving Credit Facility On June 3, 2022, we amended and restated our prior revolving credit facility by entering into the Revolving Credit Facility. As a result, we recognized a $0.5 million loss on extinguishment of debt. The Revolving Credit Facility amended our prior revolving credit facility by, among other things, (i) decreasing the lenders’ commitments from $1.75 billion to $1.40 billion, (ii) modifying the leverage ratio financial covenant calculation to net from the funded indebtedness numerator the lesser of (a) consolidated unrestricted cash of ENLC and (b) $50.0 million, (iii) removing the consolidated interest coverage ratio financial covenant, (iv) extending the maturity date from January 25, 2024 to June 3, 2027, (v) replacing the ability of ENLC to elect that borrowings accrue interest at LIBOR, plus a margin, with the ability of ENLC to elect that borrowings accrue interest at a forward-looking term rate based on SOFR (“Term SOFR”), plus a margin and a Term SOFR spread adjustment, (vi) increasing the size of a permitted receivables financing to $500.0 million from $350.0 million, and (vii) permitting, but not requiring, the establishment by ENLC (subject to approval by Bank of America, N.A., as administrative agent, and lenders holding a majority of the revolving commitments) of specified key performance indicators with respect to environmental, social, and/or governance targets that may result in a pricing increase or decrease under the Revolving Credit Facility of up to 0.05% per annum for the margin on borrowings and letters of credit and 0.02% per annum for the commitment fees. The Revolving Credit Facility will mature on June 3, 2027, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Revolving Credit Facility contains certain financial, operational, and legal covenants. The financial covenant is tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenant requires ENLC to maintain a ratio of consolidated net indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. Under the terms of the Revolving Credit Facility, if we consummate an acquisition in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated net indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Revolving Credit Facility bear interest at ENLC’s option at Term SOFR plus a Term SOFR spread adjustment of 0.10% per annum (“Adjusted Term SOFR”) and an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the federal funds rate plus 0.50%, one-month Adjusted Term SOFR plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Revolving Credit Facility, or a change in control (as defined in the Revolving Credit Facility) amounts outstanding under the Revolving Credit Facility, if any, may become due and payable immediately. ENLK is a guarantor under the Revolving Credit Facility. In the event that ENLC’s obligations under the Revolving Credit Facility are accelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of the outstanding letters of credit under the Revolving Credit Facility. There were no outstanding borrowings under the Revolving Credit Facility and $26.7 million in outstanding letters of credit as of December 31, 2023. At December 31, 2023, we were in compliance with and expect to be in compliance with the financial covenants of the Revolving Credit Facility for at least the next twelve months. AR Facility On October 21, 2020, the SPV entered into the AR Facility. In connection with the AR Facility, certain subsidiaries of ENLC sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. The SPV’s assets are not available to satisfy the obligations of ENLC or any of its affiliates. In 2021 and 2022, the SPV entered into several amendments to the AR Facility to, among other things: (i) increase the commitments thereunder to $500.0 million (ii) extend the scheduled termination date to August 1, 2025, unless extended or earlier terminated in accordance with its terms, and (iii) reduce the effective draw down fee to 0.90%. Since our investment in the SPV is not sufficient to finance its activities without additional support from us, the SPV is a variable interest entity. We are the primary beneficiary of the SPV because we have the power to direct the activities that most significantly affect its economic performance and we are obligated to absorb its losses or receive its benefits from operations. Since we are the primary beneficiary of the SPV, we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $629.3 million as of December 31, 2023. As of December 31, 2023, the AR Facility had a borrowing base of $404.2 million and there were $300.0 million in outstanding borrowings under the AR Facility. The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations. Borrowings under the AR Facility bear interest at the applicable SOFR plus a credit spread adjustment of 0.10%, plus a drawn fee in the amount of 0.90% at December 31, 2023. The SPV also pays a fee on the undrawn committed amount of the AR Facility. Interest and fees payable by the SPV under the AR Facility are due monthly. The AR Facility is scheduled to terminate on August 1, 2025, unless extended or earlier terminated in accordance with its terms, at which time no further advances will be available and the obligations under the AR Facility must be repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the AR Facility become due and payable. The AR Facility includes covenants, indemnification provisions, and events of default, including those providing for termination of the AR Facility and the acceleration of amounts owed by the SPV under the AR Facility if, among other things, a borrowing base deficiency exists, there is an event of default under the Revolving Credit Facility or certain other indebtedness, certain events negatively affecting the overall credit quality of the receivables held as collateral occur, a change in control occurs, or if the net consolidated leverage ratio of ENLC exceeds limits identical to those in the Revolving Credit Facility. At December 31, 2023, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months. Senior Unsecured Notes Redemption Provisions Each issuance of the senior unsecured notes may be fully or partially redeemed prior to an early redemption date (see “Early Redemption Date” in table below) at a redemption price equal to the greater of: (i) 100% of the principal amount of the notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the respective notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus a specified basis point premium (see “Basis Point Premium” in the table below); plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after the Early Redemption Date, the senior unsecured notes may be fully or partially redeemed at a redemption price equal to 100% of the principal amount of the applicable notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. See applicable redemption provision terms below: Issuance Maturity Date of Notes Early Redemption Date Basis Point Premium 2024 Notes April 1, 2024 Prior to January 1, 2024 25 Basis Points 2025 Notes June 1, 2025 Prior to March 1, 2025 30 Basis Points 2026 Notes July 15, 2026 Prior to April 15, 2026 50 Basis Points 2028 Notes January 15, 2028 Prior to July 15, 2027 50 Basis Points 2029 Notes June 1, 2029 Prior to March 1, 2029 50 Basis Points 2030 Notes September 1, 2030 Prior to March 1, 2030 50 Basis Points 2044 Notes April 1, 2044 Prior to October 1, 2043 30 Basis Points 2045 Notes April 1, 2045 Prior to October 1, 2044 30 Basis Points 2047 Notes June 1, 2047 Prior to December 1, 2046 40 Basis Points Senior Unsecured Notes Indentures The indentures governing the senior unsecured notes contain covenants that, among other things, limit ENLC’s and ENLK’s ability to create or incur certain liens or consolidate, merge, or transfer all or substantially all of ENLC’s and ENLK’s assets. The indentures governing the 2028 Notes and the 2030 Notes provide that if a Change of Control Triggering Event (as defined in the indenture) occurs, ENLC must offer to repurchase the 2028 Notes and the 2030 Notes at a price equal to 101% of the principal amount of such notes, plus accrued and unpaid interest to, but excluding, the date of repurchase. Each of the following is an event of default under the indentures: • failure to pay any principal or interest when due; • failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures; and • bankruptcy or other insolvency events involving ENLC and ENLK. If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies. At December 31, 2023, ENLC and ENLK were in compliance and expect to be in compliance with the covenants in the senior unsecured notes for at least the next twelve months. All interest payments for senior unsecured notes are due semi-annually, in arrears. Issuances and Repurchases of Senior Unsecured Notes On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of ENLC’s 6.50% senior unsecured notes due 2030 (the “Additional Notes”) at a price to the public of 99% of their face value. The Additional Notes were offered as an additional issuance of our existing 6.50% senior unsecured notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million. Net proceeds of approximately $294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK. On August 31, 2022, ENLC completed the sale of $700.0 million in aggregate principal amount of ENLC’s 6.50% senior unsecured notes due September 1, 2030 (the “2030 Notes”) at 100% of their face value. Interest on the 2030 Notes will be payable on March 1 and September 1 of each year beginning on March 1, 2023, until their maturity on September 1, 2030. The 2030 Notes are fully and unconditionally guaranteed by ENLK. We used the net proceeds of approximately $693.0 million and available cash to settle ENLK’s debt tender offer to repurchase $700.0 million in aggregate principal amount of its senior unsecured notes. The repurchased notes consisted of $404.4 million of outstanding aggregate principal amount of ENLK’s 4.40% senior unsecured notes due 2024 (the “2024 Notes”) and $295.6 million of outstanding aggregate principal amount of ENLK’s 4.15% senior unsecured notes due 2025 (the “2025 Notes”). Total consideration for the repurchased 2024 Notes and the 2025 Notes was $705.3 million, including $21.0 million of debt tender premium and $15.7 million of discount. Activity related to the repurchases of ENLK’s senior unsecured notes from the settled debt tender offer consisted of the following (in millions): Year Ended Debt repurchased $ 700.0 Aggregate payments (705.3) Net discount on repurchased debt (1.0) Loss on extinguishment of debt $ (6.3) Additionally, for the year ended December 31, 2022, and prior to the tender offer, we repurchased a portion of the outstanding 2024 Notes and 2025 Notes in open market transactions. Activity related to the repurchases of our senior unsecured notes in open market transactions consisted of the following (in millions): Year Ended Debt repurchased $ 23.1 Aggregate payments (22.5) Gain on extinguishment of debt $ 0.6

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	(8) Income Taxes The components of our income tax benefit (expense) are as follows (in millions): Year Ended December 31, 2023 2022 2021 Current income tax expense $ (0.7) $ (0.4) $ (0.8) Deferred income tax benefit (expense) (62.1) 95.3 (24.6) Income tax benefit (expense) $ (62.8) $ 94.9 $ (25.4) 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): Year Ended December 31, 2023 2022 2021 Expected income tax expense based on federal statutory tax rate $ (56.5) $ (55.9) $ (10.0) State income tax expense, net of federal benefit (7.2) (7.0) (1.4) Unit-based compensation (1) 7.7 0.7 (3.1) Statutory rate changes (2) — — (10.2) Change in valuation allowance (1.2) 151.6 1.7 Other (5.6) 5.5 (2.4) Total income tax benefit (expense) $ (62.8) $ 94.9 $ (25.4) ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of unit-based awards. (2) Effective January 1, 2022, Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4% and Louisiana Senate Bill No. 159 resulted in a change in the corporate income tax rate from 8% to 7.5%. Accordingly, we recorded deferred tax expense related to our Oklahoma and Louisiana operations in the amount of $7.6 million and $2.6 million, respectively, for the year ended December 31, 2021 due to a remeasurement of deferred tax assets. 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. Our deferred income tax assets and liabilities as of December 31, 2023 and 2022 are as follows (in millions): December 31, 2023 December 31, 2022 Deferred income tax assets: Federal net operating loss carryforward $ 627.2 $ 636.5 State net operating loss carryforward 77.2 77.6 Interest deduction limitation (1) 53.0 57.6 Other 2.1 2.4 Total deferred tax assets, gross 759.5 774.1 Valuation allowance (1.2) — Total deferred tax assets, net of valuation allowance 758.3 774.1 Deferred tax liabilities: Property, plant, equipment, and intangible assets (2) (862.5) (816.8) Total deferred tax liabilities (862.5) (816.8) Deferred tax liability, net $ (104.2) $ (42.7) ____________________________ (1) Related to book-to-tax differences between the allowable interest deduction amount under Section 163j of the Internal Revenue Code of 1986, as amended. (2) Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment . As of December 31, 2023, we had federal net operating loss (“NOL”) carryforwards of $3.0 billion that represented a net deferred tax asset of $627.2 million. As of December 31, 2023, we had state NOL carryforwards of $1.6 billion that represented a net deferred tax asset of $77.2 million. A portion of these carryforwards will begin expiring in 2027 through 2043. Federal NOLs incurred in 2018 and in future years (approximately $2.8 billion of our federal NOL carryforwards) may be carried forward indefinitely, but the deductibility of such federal NOLs is limited, while federal NOLs incurred prior to 2018 (approximately $0.2 billion of our NOL carryforwards) may be carried forward for only twenty years, but the deductibility of such NOL carryforwards generally is not limited unless we were to undergo an IRC Section 382 “ownership change.” We provide a valuation allowance, if necessary, to reduce deferred tax assets, if all, or some portion, of such assets will more than likely not be realized. We continually review the realizability of our deferred tax assets, including an analysis of factors such as future taxable income, reversal of existing taxable temporary differences, and tax planning strategies. We assessed whether a valuation allowance should be recorded against our deferred tax assets based on consideration of all available evidence, using a “more likely than not” standard. In assessing the need for a valuation allowance, we considered both positive and negative evidence related to the likelihood of realization of deferred tax assets. In making such assessment, more weight was given to evidence that could be objectively verified, including recent cumulative losses. Future sources of taxable income were also considered in determining the amount of the recorded valuation allowance. For the year ended December 31, 2021, we recorded a $1.7 million net reduction in the valuation allowance as a result of the remeasurement of the state deferred tax assets and liabilities from the statutory rate changes. For the year ended December 31, 2022, we further reduced the valuation allowance by $151.6 million as a result of improved current and expected future operating income. For the year ended December 31, 2023, we established a valuation allowance of $1.2 million, primarily related to state tax operating loss carryforwards for which we did not believe a tax benefit was more likely than not to be realized. As of December 31, 2023, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance. For the years ended December 31, 2023 and 2022, there was no recorded unrecognized tax benefit. Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2023, tax years 2019 through 2023 remain subject to examination by various taxing authorities. Excise Tax on Common Unit Repurchases The Inflation Reduction Act of 2022, which was enacted on August 16, 2022, includes a new tax provision that imposes a 1% excise tax on common unit repurchases, net of common unit issuances, made after December 31, 2022. As a result, we accrued $2.0 million of excise tax in connection with our net common unit repurchases for the year ended December 31, 2023, which was recorded as an adjustment to the cost basis of common units repurchased in “Members’ equity” and “Other current liabilities” on the consolidated balance sheet as of December 31, 2023.

Certain Provisions of the ENLK

Certain Provisions of the ENLK Partnership Agreement	12 Months Ended
	Dec. 31, 2023
Partners' Capital [Abstract]
Certain Provisions of the ENLK Partnership Agreement	(9) Certain Provisions of the ENLK Partnership Agreement (a) Series B Preferred Units As of December 31, 2023 and 2022, there were 54,575,638 and 54,168,359 Series B Preferred Units issued and outstanding, respectively. Issuance In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units representing ENLK limited partner interests to Enfield in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”). On August 4, 2021, Enfield Holdings, L.P. (“Enfield”) sold all of its Series B Preferred Units and ENLC Class C Common Units representing limited liability company interests in ENLC to Brookfield Infrastructure Partners L.P. and funds managed by Oaktree Capital Management, L.P. Redemptions In January 2022 and December 2021, we redeemed 3,333,334 and 3,300,330 Series B Preferred Units for total consideration of $50.5 million and $50.0 million plus accrued distributions, respectively. In addition, upon each such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price in each redemption represented 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we agreed with the holders of the Series B Preferred Units to pay cash in lieu of making a quarterly distribution in-kind of additional Series B Preferred Units (the “PIK Distribution”) through the distribution declared for the fourth quarter of 2022. Conversion and Distributions Series B Preferred Units are exchangeable for ENLC common units in an amount equal to the number of outstanding Series B Preferred Units outstanding multiplied by the exchange ratio of 1.15, subject to certain adjustments (the “Series B Exchange Ratio”). The exchange is subject to ENLK’s option to pay cash instead of issuing additional ENLC common units, and can occur in whole or in part at the option of the holder of the Series B Preferred Units at any time, or in whole at our option, provided the daily volume-weighted average closing price of the ENLC common units for the 30 trading days ending two The holder of the Series B Preferred Units is entitled to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units. The PIK Distribution equals the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the Series B Exchange Ratio, over (2) $0.28125 per Series B Preferred Unit (the “Cash Distribution Component”), divided by (y) the Issue Price. Except as described above with respect to distributions made until the distribution declared for the fourth quarter of 2022, the quarterly cash distribution (the “Series B Cash Distribution”) consists of the Cash Distribution Component plus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the PIK Distribution and (ii) the Series B Preferred Units that would have been distributed in the PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments). On September 8, 2023, in connection with ENLK’s qualification of the Series B Preferred Units to be eligible to be deposited through the Depository Trust Company, we amended and restated the limited partnership agreement of ENLK to, among other things, (i) reflect the cancellation of all outstanding ENLC Class C Common Units, which were non-economic equity interests previously held by the holders of the Series B Preferred Units and permitted such holders to participate in any vote of the holders of ENLC common units, (ii) provide for the termination of any rights of the holders of the Series B Preferred Units to PIK Distributions with respect to, and following, the earlier to occur of (x) any quarter in which the holders of the Series B Preferred Units give notice to the General Partner of its election to terminate such PIK Distribution right and (y) the quarter ending June 30, 2024, and (iii) in connection with such termination of PIK Distributions, increase the cash distribution per Series B Preferred Unit from $0.28125 to $0.31875, in addition to the continued payment of the Series B Excess Cash Payment Amount (as defined in ENLK’s limited partnership agreement). 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 years ended December 31, 2023, 2022, and 2021 is provided below: Declaration period PIK Distribution Cash distribution Date paid 2023 First Quarter of 2023 135,421 $ 15.2 May 12, 2023 Second Quarter of 2023 135,759 $ 15.3 August 11, 2023 Third Quarter of 2023 136,099 $ 15.3 November 10, 2023 Fourth Quarter of 2023 136,439 $ 15.3 February 9, 2024 2022 First Quarter of 2022 — $ 17.5 May 13, 2022 (2) Second Quarter of 2022 — $ 17.3 August 12, 2022 Third Quarter of 2022 — $ 17.3 November 14, 2022 Fourth Quarter of 2022 — $ 17.3 February 13, 2023 2021 First Quarter of 2021 150,871 $ 17.0 May 14, 2021 Second Quarter of 2021 151,248 $ 17.0 August 13, 2021 Third Quarter of 2021 151,626 $ 17.1 November 12, 2021 Fourth Quarter of 2021 — $ 19.2 February 11, 2022 (1) ____________________________ (1) In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022. (2) In January 2022, we paid $0.3 million of accrued distributions related to the first quarter of 2022 on redeemed Series B Preferred Units. The remaining distribution of $17.2 million related to the first quarter of 2022 was paid on May 13, 2022. 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 December 31, 2023, due to the application of the Allocation Cap, the cumulative amount of distributions made in respect of each Series B Preferred Unit exceeded the cumulative amount of gross income allocated to each Series B Preferred Unit by $6.79 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 December 31, 2023 and 2022, there were 366,500 and 381,000 Series C Preferred Units issued and outstanding, respectively. Issuance In September 2017, ENLK issued 400,000 Series C Preferred Units representing ENLK limited partner interests at a price to the public of $1,000 per unit. The Series C Preferred Units represent perpetual equity interests in ENLK and, unlike ENLK’s indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the Series C Preferred Units rank senior to ENLK’s common units and to each other class of limited partner interests or other equity securities established after the issue date of the Series C Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units rank junior to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event. At any time on or after December 15, 2022, ENLK may redeem, at ENLK’s option, in whole or in part, the Series C Preferred Units at a redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions, whether or not declared. ENLK may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by ENLK following certain rating agency events, ENLK may redeem, at ENLK’s option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared. Repurchases A summary of the repurchase activity relating to the Series C Preferred Units is provided below: Transaction date Series C Preferred Units Repurchased Total Consideration (in millions) Percent Represented of Repurchased Preferred Units’ Par Value 2023 February 2023 4,500 $ 3.9 87 % November 2023 3,000 $ 2.7 90 % December 2023 7,000 $ 6.5 93 % 2022 October 2022 19,000 $ 15.2 80 % 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 2023 December 15, 2022 – March 14, 2023 8.846 % $ 8.4 March 15, 2023 March 15, 2023 – June 14, 2023 9.051 % $ 8.7 June 15, 2023 June 15, 2023 – September 14, 2023 9.618 % $ 9.3 September 15, 2023 September 15, 2023 - December 14, 2023 9.782 % $ 9.3 December 15, 2023 2022 December 15, 2021 – June 14, 2022 6.000 % $ 12.0 June 15, 2022 June 15, 2022 – December 14, 2022 6.000 % $ 11.4 December 15, 2022 2021 December 15, 2020 – June 14, 2021 6.000 % $ 12.0 June 15, 2021 June 15, 2021 – December 14, 2021 6.000 % $ 12.0 December 15, 2021 ____________________________ (1) Distributions on the Series C Preferred Units accrued and were cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. (2) The initial distribution rate for the Series C Preferred Units from the date of original issue through December 14, 2022 was 6.0% per year. Starting on December 15, 2022, distributions on the Series C Preferred Units accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to the floating rate of the three-month LIBOR plus a spread of 4.11%. 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	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Members' Equity	(10) Members’ Equity (a) Common Unit Repurchase Program In November 2020, the Board authorized a common unit repurchase program, subsequently reauthorizing the program during the years ended December 31, 2023, 2022, and 2021. The table below provides a summary of the Board’s authorizations of the common unit repurchase program. Date Board Action Authorized Amount November 2020 Authorization of common unit repurchase program $ 100 April 2021 Reauthorization of common unit repurchase program $ 100 January 2022 Reauthorization of common unit repurchase program and set amount available for repurchases for 2022 $ 100 July 2022 Increase in 2022 common unit repurchase program $ 100 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) Starting on February 15, 2022, the authorized amount includes repurchases of common units held by GIP. Refer to “Note 5—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): Year Ended December 31, 2023 2022 2021 Publicly held ENLC common units 11,530,962 11,630,351 6,091,001 ENLC common units held by GIP (1) 8,846,445 6,743,703 — Total ENLC common units 20,377,407 18,374,054 6,091,001 Aggregate cost for publicly held ENLC common units $ 134.5 $ 111.5 $ 40.1 Aggregate cost for ENLC common units held by GIP 98.3 63.5 — Excise tax on common unit repurchases $ 2.0 $ — $ — Total aggregate cost for ENLC common units $ 234.8 $ 175.0 $ 40.1 Average price paid per publicly held ENLC common unit (2) $ 11.67 $ 9.59 $ 6.59 Average price paid per ENLC common unit held by GIP (2)(3) $ 11.11 $ 9.42 $ — ____________________________ (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 February 19, 2024, we repurchased 3,280,637 ENLC common units held by GIP at an aggregate cost of $41.5 million, or an average of $12.66 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 December 31, 2023. The per unit price we paid to GIP was the same as the average per unit price paid by us for publicly held ENLC common units repurchased during the same period, less broker commissions, which were not paid with respect to the GIP units. As of December 31, 2023, $41.5 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 5—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): Year Ended December 31, 2023 2022 2021 Distributed earnings allocated to: Common units (1) $ 234.3 $ 221.3 $ 192.5 Unvested unit-based awards (1) 3.9 5.2 4.5 Total distributed earnings $ 238.2 $ 226.5 $ 197.0 Undistributed income (loss) allocated to: Common units $ (31.5) $ 131.7 $ (170.6) Unvested unit-based awards (0.5) 3.1 (4.0) Total undistributed income (loss) $ (32.0) $ 134.8 $ (174.6) Net income attributable to ENLC allocated to: Common units $ 202.8 $ 353.0 $ 21.9 Unvested unit-based awards 3.4 8.3 0.5 Total net income attributable to ENLC $ 206.2 $ 361.3 $ 22.4 Net income attributable to ENLC per unit: Basic $ 0.45 $ 0.76 $ 0.05 Diluted $ 0.44 $ 0.74 $ 0.05 ____________________________ (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): Year Ended December 31, 2023 2022 2021 Basic weighted average units outstanding: Weighted average common units outstanding 461.7 478.5 488.8 Diluted weighted average units outstanding: Weighted average basic common units outstanding 461.7 478.5 488.8 Dilutive effect of unvested restricted units 4.3 6.8 5.5 Total weighted average diluted common units outstanding 466.0 485.3 494.3 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 years ended December 31, 2023, 2022, and 2021, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2023 First Quarter of 2023 $ 0.12500 May 12, 2023 Second Quarter of 2023 $ 0.12500 August 11, 2023 Third Quarter of 2023 $ 0.12500 November 10, 2023 Fourth Quarter of 2023 $ 0.13250 February 9, 2024 2022 First Quarter of 2022 $ 0.11250 May 13, 2022 Second Quarter of 2022 $ 0.11250 August 12, 2022 Third Quarter of 2022 $ 0.11250 November 14, 2022 Fourth Quarter of 2022 $ 0.12500 February 13, 2023 2021 First Quarter of 2021 $ 0.09375 May 14, 2021 Second Quarter of 2021 $ 0.09375 August 13, 2021 Third Quarter of 2021 $ 0.09375 November 12, 2021 Fourth Quarter of 2021 $ 0.11250 February 11, 2022

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(11) Investment in Unconsolidated Affiliates As of December 31, 2023, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Year Ended December 31, 2023 2022 2021 GCF Contributions $ 24.6 $ 1.5 $ — Distributions $ (2.0) $ — $ (3.5) Equity in loss $ (4.4) $ (3.2) $ (9.1) Cedar Cove JV Distributions $ (0.5) $ (0.7) $ (0.4) Equity in loss $ (2.4) $ (1.9) $ (2.4) Matterhorn JV Contributions $ 43.5 $ 64.4 $ — Equity in loss $ (1.4) $ (0.5) $ — Total Contributions $ 68.1 $ 65.9 $ — Distributions $ (2.5) $ (0.7) $ (3.9) Equity in loss $ (8.2) $ (5.6) $ (11.5) The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2023 and 2022 (in millions): December 31, 2023 December 31, 2022 GCF $ 44.5 $ 26.3 Cedar Cove JV (1) (7.3) (4.4) Matterhorn JV 106.0 63.9 Total investment in unconsolidated affiliates $ 143.2 $ 85.8 ___________________________ (1)

Employee Incentive Plans

Employee Incentive Plans	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Employee Incentive Plans	(12) 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): Year Ended December 31, 2023 2022 2021 Cost of unit-based compensation charged to operating expense $ 3.7 $ 5.7 $ 6.6 Cost of unit-based compensation charged to general and administrative expense 15.5 24.7 18.7 Total unit-based compensation expense $ 19.2 $ 30.4 $ 25.3 Amount of related income tax benefit recognized in net income (1) $ 4.5 $ 7.1 $ 5.9 ____________________________ (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 8—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 year ended December 31, 2023 is provided below: Year Ended December 31, 2023 Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 6,775,186 $ 5.89 Granted (1) 1,587,965 11.03 Vested (1)(2) (2,489,603) 5.96 Forfeited (427,568) 6.98 Unvested, end of period 5,445,980 $ 7.27 Aggregate intrinsic value, end of period (in millions) $ 66.2 ____________________________ (1) Restricted incentive units typically vest at the end of three years. (2) Vested units included 756,556 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 years ended December 31, 2023, 2022, and 2021 is provided below (in millions): Year Ended December 31, Restricted Incentive Units: 2023 2022 2021 Aggregate intrinsic value of units vested $ 30.5 $ 24.4 $ 5.6 Fair value of units vested $ 14.8 $ 19.0 $ 16.3 As of December 31, 2023, there were $16.7 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 1.8 years. For restricted incentive unit awards granted to certain officers and employees (the “grantee”), such awards (the “Subject Grants”) generally provide that, subject to the satisfaction of the conditions set forth in the agreement, the Subject Grants will vest on the third anniversary of the vesting commencement date (the “Regular Vesting Date”). The Subject Grants will be forfeited if the grantee’s employment or service with ENLC and its affiliates terminates prior to the Regular Vesting Date except that the Subject Grants will vest in full or on a pro-rated basis for certain terminations of employment or service prior to the Regular Vesting Date. For instance, the Subject Grants will vest on a pro-rated basis for any terminations of the grantee’s employment: (i) due to retirement, (ii) by ENLC or its affiliates without cause, or (iii) by the grantee for good reason (each, a “Covered Termination” and more particularly defined in the Subject Grants agreement) except that the Subject Grants will vest in full if the applicable Covered Termination is a “normal retirement” (as defined in the Subject Grants agreement) or the applicable Covered Termination occurs after a change in control (if any). The Subject Grants will vest in full if death or a qualifying disability occurs prior to the Regular Vesting Date. (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. Performance Unit Awards Vesting The vesting of performance units is dependent on (a) the grantee’s continued employment or service with ENLC or its affiliates for all relevant periods and (b) the TSR performance of ENLC (the “ENLC TSR”) and a performance goal based on cash flow, which in previous years has been based on distributable cash flow (“DCF”) or free cash flow after distributions (“FCFAD”) (as applicable “Cash Flow”). At the time of grant, the Board will determine the relative weighting of the two performance goals by including in the award agreement the number of units that will be eligible for vesting depending on the achievement of the TSR performance goals (the “Total TSR Units”) versus the achievement of the Cash Flow performance goals (the “Total CF Units”). These performance awards have four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date of the performance awards and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”). One-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to each of the four performance periods described above. Following the end date of a given performance period, the Governance and Compensation Committee (the “Committee”) of the Board will measure and determine the ENLC TSR relative to the TSR performance of a designated group of peer companies (the “Designated Peer Companies”) to determine the Tranche TSR Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end date of the Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period. The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies: Performance Level Achieved ENLC TSR Vesting Percentage of the Tranche TSR Units Below Threshold Less than 25% 0% Threshold Equal to 25% 50% Target Equal to 50% 100% Maximum Greater than or Equal to 85% (1) 200% ____________________________ (1) The performance awards granted prior to 2023 achieved the maximum performance level if the ENLC TSR position relative to designated peer companies was greater than or equal to 75%. Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not have a Cumulative Performance Period). The Board will establish the Cash Flow performance targets for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In 2023, the Board adopted the DCF metric as the Cash Flow performance goal in the Performance-Based Award Agreement for all periods beginning after January 1, 2023, rather than the previously used FCFAD metric. The following table sets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation): Performance Period Ended December 31, 2023 2022 2021 Performance Level Vesting Percentage of the Tranche CF Units Achieved DCF Achieved FCFAD Achieved FCFAD Below Threshold 0% Less than $801 million Less than $154 million Less than $205 million Threshold 50% Equal to $801 million Equal to $154 million Equal to $205 million Target 100% Equal to $932 million Equal to $202 million Equal to $256 million Maximum 200% Greater than or Equal to $1,123 million Greater than or Equal to $241 million Greater than or Equal to $300 million The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the Designated Peer Companies’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC among the Designated Peer Companies or Peer Companies, and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: Performance Units: March 2023 June 2022 March 2022 (1) January 2021 Grant-date fair value $ 11.67 $ 11.71 $ 11.90 $ 4.70 Beginning TSR price $ 10.40 $ 8.54 $ 8.83 $ 3.71 Risk-free interest rate 3.76 % 3.35 % 2.15 % 0.17 % Volatility factor 64.00 % 76.00 % 75.00 % 71.00 % ____________________________ (1) Excludes certain performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 performance units have a grant-date fair value of $8.90 and were scheduled to vest in February 2023. However, this award partially vested in October 2022 and is reflected in the “Vested” row of the summary of the performance units table below. The following table presents a summary of the performance units: Year Ended December 31, 2023 Performance Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 2,979,154 $ 6.44 Granted 420,128 11.67 Vested (1) (1,091,523) 8.30 Forfeited (71,015) 10.97 Unvested, end of period 2,236,744 $ 6.37 Aggregate intrinsic value, end of period (in millions) $ 27.2 ____________________________ (1) Vested units included 811,114 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 years ended December 31, 2023, 2022, and 2021 is provided below (in millions). Year Ended December 31, Performance Units: 2023 2022 2021 Aggregate intrinsic value of units vested $ 26.1 $ 20.4 $ 0.6 Fair value of units vested $ 9.1 $ 26.2 $ 4.4 As of December 31, 2023, there were $8.7 million of unrecognized compensation costs that related to unvested performance units. These costs are expected to be recognized over a weighted-average period of 1.4 years. (d) Benefit Plan

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(13) Derivatives Interest Rate Swaps In January 2023, we entered into a $400.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, SOFR-based borrowings, including borrowings on the Revolving Credit Facility and the AR Facility. Under this arrangement, we pay a fixed interest rate of 3.8565% in exchange for SOFR-based variable interest through February 2026. Assets or liabilities related to this interest rate swap contract are included in the fair value of derivative assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract is recorded net as a gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). We designated this interest rate swap as a cash flow hedge in accordance with ASC 815. There is no ineffectiveness related to this hedge. In April 2019, we entered into $850.0 million of interest rate swaps to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. For the year ended December 31, 2021, we terminated $200.0 million of interest rate swaps, resulting in a $1.8 million payment, while the remaining $150.0 million of interest rate swaps expired on December 10, 2021. The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps are as follows (in millions): Year Ended December 31, 2023 2022 2021 Change in fair value of interest rate swaps $ 0.9 $ 1.9 $ 18.2 Tax expense (0.2) (0.5) (4.3) Unrealized gain on designated cash flow hedge $ 0.7 $ 1.4 $ 13.9 The fair value of derivative assets and liabilities related to the interest rate swaps are as follows (in millions): Year Ended December 31, 2023 2022 Fair value of derivative assets—current $ 3.3 $ — Fair value of derivative liabilities—long-term (2.4) — Net fair value of interest rate swaps $ 0.9 $ — Interest expense (income) is recognized from accumulated other comprehensive income from the monthly settlement of our interest rate swaps and was included in our consolidated statements of operations as follows (in millions): Year Ended December 31, 2023 2022 2021 Interest expense (income) $ (4.5) $ 1.9 $ 18.3 We expect to recognize an additional $3.3 million of interest income out of accumulated other comprehensive income (loss) over the next twelve months. Commodity Derivatives We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations by utilizing various OTC and exchange-traded commodity financial instrument contracts. Commodity swaps and futures are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swaps or futures as cash flow or fair value hedges for hedge accounting treatment under ASC 815. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our commodity risk management policy does not allow us to take speculative positions with our derivative contracts. We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs, and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced natural gas versus first-of-month priced natural gas. For condensate, crude oil, and natural gas, index swaps are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. Similarly, we use futures in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, crude, and condensate. For natural gas, NGLs, condensate, and crude oil, fixed-for-float swaps and futures are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party natural gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage. Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities, and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity on the consolidated statements of operations. We estimate the fair value of all of our derivative contracts based upon actively-quoted prices of the underlying commodities. The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity derivatives are as follows (in millions): Year Ended December 31, 2023 2022 2021 Change in fair value of derivatives $ (12.1) $ 40.2 $ (12.4) Realized gain (loss) on derivatives 32.8 (25.9) (146.7) Gain (loss) on derivative activity $ 20.7 $ 14.3 $ (159.1) The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): December 31, 2023 December 31, 2022 Fair value of derivative assets—current $ 73.6 $ 68.4 Fair value of derivative assets—long-term 27.0 2.9 Fair value of derivative liabilities—current (62.7) (42.9) Fair value of derivative liabilities—long-term (24.3) (2.7) Net fair value of commodity derivatives $ 13.6 $ 25.7 Set forth below are the summarized notional volumes and fair values of all instruments related to commodity derivatives that we held for price risk management purposes and the related physical offsets at December 31, 2023 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028. December 31, 2023 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps MMgals (111.8) $ (0.8) NGL (long contracts) Swaps MMgals 58.0 1.1 Natural gas (short contracts) Swaps and futures Bbtu (145.8) 86.6 Natural gas (long contracts) Swaps and futures Bbtu 122.4 (75.5) Crude and condensate (short contracts) Swaps and futures MMbbls (7.4) 2.3 Crude and condensate (long contracts) Swaps and futures MMbbls 0.1 (0.1) Total fair value of commodity derivatives $ 13.6

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value Measurements	(14) Fair Value Measurements ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our derivative contracts primarily consist of commodity swap and futures contracts, which are not traded on a public exchange. The fair values of commodity swap and futures contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly-quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate, and credit risk and are classified as Level 2 in hierarchy. Derivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2023 December 31, 2022 Interest rate swaps (1) $ 0.9 $ — Commodity derivatives (2) $ 13.6 $ 25.7 ____________________________ (1) The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. (2) The fair values of commodity derivatives represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820. Fair Value of Financial Instruments The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): December 31, 2023 December 31, 2022 Carrying Value Fair Value Carrying Value Fair Value Long-term debt, including current maturities of long-term debt (1) $ 4,568.9 $ 4,427.0 $ 4,723.5 $ 4,385.9 Contingent consideration (2)(3) $ 6.7 $ 6.7 $ 5.5 $ 5.5 ____________________________ (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance cost, net of accumulated amortization, of $32.1 million and $34.9 million as of December 31, 2023 and 2022, respectively. The respective fair values do not factor in debt issuance costs. (2) Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable, if at all, between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. (3) Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable, if at all, between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. The fair values of all senior unsecured notes as of December 31, 2023 and 2022 were based on Level 2 inputs from third-party market quotations.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(15) Commitments and Contingencies (a) Change in Control and Severance Agreements Certain members of our management are parties to severance and change in control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individuals from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change in control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment. (b) Environmental Issues The operation of pipelines, plants, and other facilities for the gathering, processing, transmitting, stabilizing, fractionating, storing, or disposing of natural gas, NGLs, crude oil, condensate, brine, and other products is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner, partner, or operator of these facilities, we must comply with United States laws and regulations at the federal, state, and local levels that relate to air and water quality, hazardous and solid waste management and disposal, oil spill prevention, climate change, endangered species, and other environmental matters. The cost of planning, designing, constructing, and operating pipelines, plants, and other facilities must account for compliance with environmental laws and regulations and safety standards. Federal, state, or local administrative decisions, developments in the federal or state court systems, or other governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition, or cash flows. However, we cannot provide assurance that future events, such as changes in existing laws, regulations, or enforcement policies, the promulgation of new laws or regulations, or the discovery or development of new factual circumstances will not cause us to incur material costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation. (c) Litigation 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. The dispute centers on whether EnLink Gas was excused from delivering natural gas or performing under certain delivery or purchase obligations during Winter Storm Uri, given our declaration of force majeure during the storm. Koch has invoiced us approximately $53.9 million (after subtracting amounts owed to EnLink Gas) and does not recognize the declaration of force majeure. We believe the declaration of force majeure was valid and appropriate and we intend to vigorously defend against Koch’s claims. One of our subsidiaries, EnLink Energy GP, LLC (“EnLink Energy”), was involved in industry-wide multi-district litigation arising out of Winter Storm Uri, pending in Harris County, Texas, in which multiple individual plaintiffs asserted personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators, transmission/distribution utility, retail electric provider, and natural gas defendants across over 150 filed cases. On January 26, 2023, the court dismissed the claims against the pipeline and other natural gas-related defendants in the multi-district litigation, including EnLink Energy. The court’s order was not appealed and the case is continuing without EnLink Energy and the other natural gas-related defendants. Subsequently, several suits were filed in February 2023 by individual plaintiffs (including one matter in which the plaintiffs seek to certify a class of Texas residents affected by Winter Storm Uri) and the alleged assignee of the claims of individual plaintiffs against approximately 90 natural gas producers, pipelines, marketers, sellers, and traders, including EnLink Gas. EnLink Gas believes it has substantial defenses to these claims and intends to vigorously dispute these allegations and defend against such claims.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Segment Information	(16) 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 7. 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 Year Ended December 31, 2023 Natural gas sales $ 453.4 $ 444.7 $ 184.5 $ 76.6 $ — $ 1,159.2 NGL sales (12.0) 3,031.2 8.5 (6.2) — 3,021.5 Crude oil and condensate sales 1,250.0 215.6 109.3 — — 1,574.9 Product sales 1,691.4 3,691.5 302.3 70.4 — 5,755.6 NGL sales—related parties 927.9 22.4 465.6 295.9 (1,711.8) — Crude oil and condensate sales—related parties — — — 10.5 (10.5) — Product sales—related parties 927.9 22.4 465.6 306.4 (1,722.3) — Gathering and transportation 114.6 79.9 236.8 203.9 — 635.2 Processing 60.1 1.6 144.4 123.4 — 329.5 NGL services — 87.3 — 0.2 — 87.5 Crude services 23.9 19.6 17.5 0.7 — 61.7 Other services 7.3 1.3 0.5 0.8 — 9.9 Midstream services 205.9 189.7 399.2 329.0 — 1,123.8 NGL services—related parties — — — 3.7 (3.7) — Midstream services—related parties — — — 3.7 (3.7) — Revenue from contracts with customers 2,825.2 3,903.6 1,167.1 709.5 (1,726.0) 6,879.4 Realized gain on derivatives 3.0 2.6 6.5 20.7 — 32.8 Change in fair value of derivatives (5.0) 4.1 (2.2) (9.0) — (12.1) Total revenues 2,823.2 3,910.3 1,171.4 721.2 (1,726.0) 6,900.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (2,205.5) (3,388.4) (645.6) (342.6) 1,726.0 (4,856.1) Adjusted gross margin 617.7 521.9 525.8 378.6 — 2,044.0 Operating expenses (221.3) (130.3) (103.8) (102.8) — (558.2) Segment profit 396.4 391.6 422.0 275.8 — 1,485.8 Depreciation and amortization (166.6) (151.3) (217.7) (115.8) (5.7) (657.1) Gross margin 229.8 240.3 204.3 160.0 (5.7) 828.7 Impairments — (20.7) — — — (20.7) Gain (loss) on disposition of assets 0.2 (2.0) 0.9 1.2 — 0.3 General and administrative — — — — (115.5) (115.5) Interest expense, net of interest income — — — — (271.7) (271.7) Loss from unconsolidated affiliate investments — — — — (8.2) (8.2) Other loss — — — — (0.1) (0.1) Income (loss) before non-controlling interest and income taxes $ 230.0 $ 217.6 $ 205.2 $ 161.2 $ (401.2) $ 412.8 Capital expenditures $ 267.3 $ 68.6 $ 69.2 $ 75.5 $ 6.2 $ 486.8 Permian Louisiana Oklahoma North Texas Corporate Totals Year Ended December 31, 2022 Natural gas sales $ 1,078.7 $ 1,128.4 $ 367.5 $ 139.0 $ — $ 2,713.6 NGL sales (1.5) 4,196.6 10.8 1.4 — 4,207.3 Crude oil and condensate sales 1,158.6 350.0 135.4 — — 1,644.0 Product sales 2,235.8 5,675.0 513.7 140.4 — 8,564.9 NGL sales—related parties 1,495.6 97.7 774.6 543.6 (2,911.5) — Crude oil and condensate sales—related parties — — 0.3 12.3 (12.6) — Product sales—related parties 1,495.6 97.7 774.9 555.9 (2,924.1) — Gathering and transportation 72.6 75.5 187.5 185.7 — 521.3 Processing 39.2 1.5 119.7 125.9 — 286.3 NGL services — 82.0 — 0.2 — 82.2 Crude services 21.4 33.3 14.9 0.7 — 70.3 Other services 0.8 1.6 (0.3) 0.7 — 2.8 Midstream services 134.0 193.9 321.8 313.2 — 962.9 NGL services—related parties — — — 1.6 (1.6) — Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 0.2 — — (0.2) — Midstream services—related parties — 0.2 0.1 1.6 (1.9) — Revenue from contracts with customers 3,865.4 5,966.8 1,610.5 1,011.1 (2,926.0) 9,527.8 Realized gain (loss) on derivatives (9.0) 2.9 (13.1) (6.7) — (25.9) Change in fair value of derivatives 9.6 7.7 5.6 17.3 — 40.2 Total revenues 3,866.0 5,977.4 1,603.0 1,021.7 (2,926.0) 9,542.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (3,280.3) (5,462.4) (1,124.4) (631.7) 2,926.0 (7,572.8) Adjusted gross margin 585.7 515.0 478.6 390.0 — 1,969.3 Operating expenses (200.2) (140.7) (90.9) (93.1) — (524.9) Segment profit 385.5 374.3 387.7 296.9 — 1,444.4 Depreciation and amortization (154.5) (156.5) (201.8) (121.1) (5.5) (639.4) Gross margin 231.0 217.8 185.9 175.8 (5.5) 805.0 Gain (loss) on disposition of assets 0.1 (13.8) 0.5 (4.8) — (18.0) General and administrative — — — — (125.2) (125.2) Interest expense, net of interest income — — — — (245.0) (245.0) Loss on extinguishment of debt — — — — (6.2) (6.2) Loss from unconsolidated affiliate investments — — — — (5.6) (5.6) Other income — — — — 0.8 0.8 Income (loss) before non-controlling interest and income taxes $ 231.1 $ 204.0 $ 186.4 $ 171.0 $ (386.7) $ 405.8 Capital expenditures $ 210.2 $ 33.7 $ 63.8 $ 22.8 $ 7.1 $ 337.6 Permian Louisiana Oklahoma North Texas Corporate Totals Year Ended December 31, 2021 Natural gas sales $ 609.4 $ 693.5 $ 213.4 $ 150.0 $ — $ 1,666.3 NGL sales 0.9 3,353.1 2.0 1.1 — 3,357.1 Crude oil and condensate sales 677.4 212.0 81.2 — — 970.6 Product sales 1,287.7 4,258.6 296.6 151.1 — 5,994.0 NGL sales—related parties 1,008.4 129.7 630.8 447.0 (2,215.9) — Crude oil and condensate sales—related parties — — 0.1 7.1 (7.2) — Product sales—related parties 1,008.4 129.7 630.9 454.1 (2,223.1) — Gathering and transportation 46.8 64.7 186.9 157.0 — 455.4 Processing 29.1 2.4 98.7 108.3 — 238.5 NGL services — 82.6 — 0.3 — 82.9 Crude services 18.4 39.3 12.8 0.7 — 71.2 Other services 0.2 1.7 0.6 0.5 — 3.0 Midstream services 94.5 190.7 299.0 266.8 — 851.0 Crude services—related parties — — 0.3 — (0.3) — Other services—related parties — 2.4 — — (2.4) — Midstream services—related parties — 2.4 0.3 — (2.7) — Revenue from contracts with customers 2,390.6 4,581.4 1,226.8 872.0 (2,225.8) 6,845.0 Realized loss on derivatives (75.6) (42.3) (22.6) (6.2) — (146.7) Change in fair value of derivatives (7.7) 0.7 — (5.4) — (12.4) Total revenues 2,307.3 4,539.8 1,204.2 860.4 (2,225.8) 6,685.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,996.1) (4,091.2) (796.6) (531.8) 2,225.8 (5,189.9) Adjusted gross margin 311.2 448.6 407.6 328.6 — 1,496.0 Operating expenses (81.5) (123.7) (80.0) (77.7) — (362.9) Segment profit 229.7 324.9 327.6 250.9 — 1,133.1 Depreciation and amortization (139.9) (141.0) (204.3) (114.3) (8.0) (607.5) Gross margin 89.8 183.9 123.3 136.6 (8.0) 525.6 Impairments — (0.6) — — (0.2) (0.8) Gain on disposition of assets — 1.2 — 0.3 — 1.5 General and administrative — — — — (107.8) (107.8) Interest expense, net of interest income — — — — (238.7) (238.7) Loss from unconsolidated affiliate investments — — — — (11.5) (11.5) Income (loss) before non-controlling interest and income taxes $ 89.8 $ 184.5 $ 123.3 $ 136.9 $ (366.2) $ 168.3 Capital expenditures $ 141.6 $ 9.3 $ 30.4 $ 11.9 $ 2.8 $ 196.0 The table below represents information about segment assets as of December 31, 2023 and 2022 (in millions): Segment Identifiable Assets: December 31, 2023 December 31, 2022 Permian $ 2,813.6 $ 2,661.4 Louisiana 2,031.8 2,310.7 Oklahoma 2,275.8 2,420.4 North Texas 1,017.7 1,094.6 Corporate (1) 189.7 163.9 Total identifiable assets $ 8,328.6 $ 8,651.0 ____________________________ (1)

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2023
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(17) Supplemental Cash Flow Information The following schedule summarizes cash paid for interest, cash paid (refunded) for income taxes, cash paid for operating leases included in cash flows from operating activities, non-cash investing activities, and non-cash financing activities for the periods presented (in millions): Year Ended December 31, Supplemental disclosures of cash flow information: 2023 2022 2021 Cash paid for interest $ 266.9 $ 221.1 $ 208.8 Cash paid for income taxes $ 1.6 $ 0.7 $ 0.3 Cash paid for operating leases included in cash flows from operating activities $ 35.1 $ 30.5 $ 24.6 Non-cash investing activities: Non-cash accrual of property and equipment $ 41.1 $ 4.2 $ 12.0 Non-cash right-of-use assets obtained in exchange for operating lease liabilities $ 36.5 $ 33.4 $ 18.7 Non-cash acquisitions $ — $ 1.3 $ 16.9 Non-cash financing activities: Redemption of mandatorily redeemable non-controlling interest $ — $ (6.5) $ —

Other Information

Other Information	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Other Information	(18) 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: December 31, 2023 December 31, 2022 Product inventory $ 46.4 $ 147.1 Prepaid expenses and other 19.0 19.5 Other current assets $ 65.4 $ 166.6 Other current liabilities: December 31, 2023 December 31, 2022 Accrued interest $ 63.4 $ 57.6 Accrued wages and benefits, including taxes 23.2 38.1 Accrued ad valorem taxes 33.3 32.0 Accrued settlement of mandatorily redeemable non-controlling interest (1) — 10.5 Capital expenditure accruals 64.6 23.4 Short-term lease liability 28.2 26.2 Operating expense accruals 21.5 18.5 Other 44.3 23.3 Other current liabilities $ 278.5 $ 229.6 ____________________________ (1) In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 206.2	$ 361.3	$ 22.4

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
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)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. 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.
Management's Use of Estimates	Management’s Use of Estimates
Revenue Recognition	Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows: • Product sales— Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above. • Midstream services— Midstream services represent all other revenue generated as a result of performing our midstream services outlined above. Evaluation of Our Contractual Performance Obligations Performance obligations in our contracts with customers include: • promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and • promises to sell a specified volume of commodities to our customers. The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Accounting Methodology for Certain Contracts For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of the commodities purchased. We account for the contractually-stated fees on the consolidated statements of operations as a reduction of cost of sales of such commodities purchased upon receipt of the raw mix NGLs, because we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased. For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under as outlined above for NGL contracts. For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories: • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased, net of fees. • For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations. For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our natural gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Satisfaction of Performance Obligations and Recognition of Revenue For our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. We recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. Prior to issuing our financial statements, we review our revenue and purchases estimates based on available information to determine if adjustments are required. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). Minimum Volume Commitments and Firm Transportation Contracts
Imbalance Accounting	Imbalance Accounting Quantities of natural gas, NGLs, or crude and condensate over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas, NGLs, or crude and condensate. We had imbalance payables of $6.3 million and $17.3 million at December 31, 2023 and 2022, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $8.0 million and $20.2 million at December 31, 2023 and 2022, respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line
Cash and Cash Equivalents	Cash and Cash Equivalents
Income Taxes	Income Taxes Certain of our operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of our operations are subject to tax assessed by the state of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas franchise tax is presented as income tax expense in the accompanying statements of operations. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. We record deferred tax assets and liabilities on a net basis on the consolidated balance sheets, with deferred tax assets included in “Other assets, net” and deferred tax liabilities included in “Deferred tax liability, net.”
Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory	Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory
Property and Equipment	Property and Equipment Property and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value. Routine repairs and maintenance are charged against income when incurred. Renewals and improvements that extend the useful life or improve the function of the properties are capitalized. The components of property and equipment, net of accumulated depreciation are as follows (in millions): Year Ended December 31, 2023 2022 Transmission assets $ 1,459.5 $ 1,452.0 Gathering systems 5,472.4 5,370.0 Natural gas processing plants and fractionation facilities 4,279.1 4,237.8 Other property and equipment 90.1 165.0 Construction in process 243.1 105.7 Property and equipment 11,544.2 11,330.5 Accumulated depreciation (5,137.2) (4,774.5) Property and equipment, net of accumulated depreciation $ 6,407.0 $ 6,556.0 Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Natural gas processing plants and fractionation facilities 20 - 25 years Other property and equipment 3 - 25 years Gain or Loss on Disposition. Upon the disposition or retirement of property and equipment, any gain or loss is recognized in operating income in the consolidated statements of operations. For the years ended December 31, 2023, 2022, and 2021, dispositions primarily related to the sale of certain non-core assets. The (gain) loss on disposition of assets is as follows (in millions): Year Ended December 31, 2023 2022 2021 Net book value of assets disposed $ 72.9 $ 30.8 $ 3.3 Proceeds from sales (73.1) (12.8) (4.8) Insurance recoveries (0.1) — — (Gain) loss on disposition of assets $ (0.3) $ 18.0 $ (1.5) Impairment Review . 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. When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding: • the future fee-based rate of new business or contract renewals; • the purchase and resale margins on natural gas, NGLs, crude oil, and condensate; • the volume of natural gas, NGLs, crude oil, and condensate available to the asset; • markets available to the asset; • operating expenses; and • future natural gas, NGLs, crude oil, and condensate prices. The estimated volume of natural gas, NGLs, crude oil, and condensate available to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil, and condensate prices. Projections of natural gas, NGL, crude oil, and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to: • changes in general economic conditions or demand for our products in regions in which our markets are located; • the availability and prices of natural gas, NGLs, crude oil, and condensate supply; • our ability to negotiate favorable sales agreements; • the risks that natural gas, NGLs, crude oil, and condensate exploration and production activities will not occur or be successful; • our dependence on certain key customers, producers, and transporters of natural gas, NGLs, crude oil, and condensate; and •
Comprehensive Income (Loss)	Comprehensive Income (Loss)
Equity Method of Accounting	Equity Method of Accounting We account for investments where we do not control the investment but have the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. We recognize impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations.
Non-controlling Interests	Non-controlling Interests We account for investments where we control the investment using the consolidation method of accounting. Under this method, we consolidate all the assets and liabilities of an investment on our consolidated balance sheets and record non-controlling interest for the portion of the investment that we do not own. We include all of an investment’s results of operations on our consolidated statements of operations and record income attributable to non-controlling interests for the portion of the investment that we do not own. Our non-controlling interests for the years ended December 31, 2023, 2022, and 2021 are comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50.0% share of the Ascension JV. Certain of our joint venture arrangements provide our joint venture partners with the right, under certain circumstances, to cause us to purchase their interest in the joint venture or to seek to sell the entire joint venture. For example, at any time after June 30, 2025, NGP has the right to cause the Delaware Basin JV to sell all of the outstanding interests or assets of the Delaware Basin JV for the best available price; provided that, if NGP exercises this right, we are permitted to purchase NGP’s interest at a certain call price.
Intangible Assets	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 range from ten Intangibles—Goodwill and Other
Asset Retirement Obligations	Asset Retirement Obligations
Leases	Leases We account for leases under ASC 842 whereby we recognized leases on our consolidated balance sheet by recording a right-of-use asset and lease liability.
Derivatives	Derivatives We use derivative instruments to hedge against changes in cash flows related to product price. We generally determine the fair value of swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet at the fair value of derivative assets or liabilities in accordance with ASC 815. Changes in fair value of derivative instruments are recorded in gain or loss on derivative activity in the period of change. Realized gains and losses on commodity-related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statements of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities. We periodically enter into interest rate swaps to hedge variability in interest rates and effectively lock in the benchmark interest rate at the inception of the swap. The change in fair value of interest rate swaps is recorded net as a gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss).
Concentrations of Credit Risk	Concentrations of Credit Risk Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than our exposure to key customers discussed below, since our customers represent a broad and diverse group of energy marketers and end-users.
Environmental Costs	Environmental Costs
Commitments and Contingencies	Commitments and Contingencies
Debt Issuance Costs	Debt Issuance Costs
Redeemable Non-Controlling Interest	Redeemable Non-Controlling Interest

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table summarizes the contractually committed fees (in millions) that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods. Contractually Committed Fees Commitments 2024 $ 145.0 2025 126.2 2026 126.6 2027 105.9 2028 97.1 Thereafter 1,032.9 Total $ 1,633.7
Property, Plant and Equipment	The components of property and equipment, net of accumulated depreciation are as follows (in millions): Year Ended December 31, 2023 2022 Transmission assets $ 1,459.5 $ 1,452.0 Gathering systems 5,472.4 5,370.0 Natural gas processing plants and fractionation facilities 4,279.1 4,237.8 Other property and equipment 90.1 165.0 Construction in process 243.1 105.7 Property and equipment 11,544.2 11,330.5 Accumulated depreciation (5,137.2) (4,774.5) Property and equipment, net of accumulated depreciation $ 6,407.0 $ 6,556.0 Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows: Useful Lives Transmission assets 20 - 25 years Gathering systems 20 - 25 years Natural gas processing plants and fractionation facilities 20 - 25 years Other property and equipment 3 - 25 years
Schedule of Gain or Loss on Disposition of Assets	The (gain) loss on disposition of assets is as follows (in millions): Year Ended December 31, 2023 2022 2021 Net book value of assets disposed $ 72.9 $ 30.8 $ 3.3 Proceeds from sales (73.1) (12.8) (4.8) Insurance recoveries (0.1) — — (Gain) loss on disposition of assets $ (0.3) $ 18.0 $ (1.5)
Schedule of Property and Equipment Impairment Expense	We recognized impairment expense related to property and equipment as follows (in millions): Year Ended December 31, 2023 2022 2021 Property and equipment impairment (1) $ 20.7 $ — $ 0.6 ____________________________ (1) During the third quarter of 2023, we identified changes in our outlook for future cash flows and the anticipated use of certain ORV crude assets in our Louisiana segment. We determined that the carrying amounts of these assets exceeded their fair values, based on market inputs and certain assumptions.
Schedules of Concentration of Risk, by Risk Factor	The following customers individually represented greater than 10% of our consolidated revenues for the years ended December 31, 2023, 2022, or 2021. No other customers represented greater than 10% of our consolidated revenues during the periods presented. Year Ended December 31, 2023 2022 2021 Dow Hydrocarbons and Resources LLC 10.4 % 14.2 % 14.5 % Marathon Petroleum Corporation 19.3 % 14.7 % 13.4 %

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Schedule of Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 50.6 Installment payable 10.0 Contingent consideration fair value (1) 6.9 Total consideration: $ 67.5 Purchase price allocation Assets acquired: Current assets (including $1.3 million in cash) $ 1.4 Property and equipment 16.3 Intangible assets 50.6 Other assets, net (2) 0.6 Liabilities assumed: Current liabilities (0.8) Other long-term liabilities (2) (0.6) Net assets acquired $ 67.5 ____________________________ (1) The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from the estimated fair values. (2) “Other assets, net” and “Other long-term liabilities” consist of the right-of-use asset and lease liability, respectively, recorded through the acquisition of Amarillo Rattler, LLC. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 289.5 Purchase price allocation Assets acquired: Current assets $ 17.3 Property and equipment 275.0 Liabilities assumed: Current liabilities (2.8) Net assets acquired $ 289.5 The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 100.9 Contingent consideration 1.3 Total consideration $ 102.2 Purchase price allocation Assets acquired: Current assets $ 6.0 Property and equipment 97.1 Other assets, net (1) 0.9 Liabilities assumed: Current liabilities (1.4) Other long-term liabilities (1) (0.4) Net assets acquired $ 102.2 ____________________________ (1) “Other assets, net” and “Other long-term liabilities” consist of the right-of-use assets and lease liabilities, respectively, obtained through the Central Oklahoma Acquisition.
Schedule of Asset Acquisition, Contingent Consideration	The following table represents our change in carrying value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities for the periods presented (in millions): Year Ended December 31, 2023 2022 2021 Amarillo Rattler Acquisition contingent consideration Contingent consideration liability, beginning of period $ 4.2 $ 6.9 $ — Contingent consideration liability recorded upon acquisition (1) — — 6.9 Change in fair value 0.6 (2.7) — Contingent consideration liability, end of period $ 4.8 $ 4.2 $ 6.9 Central Oklahoma Acquisition contingent consideration Contingent consideration liability, beginning of period $ 1.3 $ — $ — Contingent consideration liability recorded upon acquisition (2) — 1.3 — Change in fair value 0.6 — — Contingent consideration liability, end of period $ 1.9 $ 1.3 $ — Total contingent consideration Contingent consideration liability, beginning of period $ 5.5 $ 6.9 $ — Contingent consideration liability recorded upon acquisition (1)(2) — 1.3 6.9 Change in fair value 1.2 (2.7) — Contingent consideration liability, end of period $ 6.7 $ 5.5 $ 6.9 ____________________________ (1) The contingent consideration for the Amarillo Rattler Acquisition was recorded on April 30, 2021. (2) The contingent consideration for the Central Oklahoma Acquisition was recorded on December 19, 2022.
Schedule of Pro Forma Information	The following unaudited pro forma condensed consolidated financial information (in millions) for the years ended December 31, 2022 and 2021 gives effect to the Barnett Shale Acquisition on July 1, 2022 and the Central Oklahoma Acquisition on December 19, 2022 as if each of the acquisitions had occurred on January 1, 2021. On a historical pro forma basis, our consolidated revenues, net income (loss), total assets, and earnings per unit amounts would not have differed materially had the Amarillo Rattler Acquisition been completed on January 1, 2021 rather than April 30, 2021. The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. Year Ended December 31, 2022 2021 Pro forma total revenues $ 9,630.4 $ 6,782.9 Pro forma net income $ 534.3 $ 157.5

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Changes in Carrying Value	The following table represents our change in carrying value of intangible assets for the periods stated (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Year Ended December 31, 2023 Customer relationships, beginning of period $ 1,844.8 $ (923.6) $ 921.2 Amortization expense — (127.6) (127.6) Customer relationships, end of period $ 1,844.8 $ (1,051.2) $ 793.6 Year Ended December 31, 2022 Customer relationships, beginning of period $ 1,844.8 $ (795.1) $ 1,049.7 Amortization expense — (128.5) (128.5) Customer relationships, end of period $ 1,844.8 $ (923.6) $ 921.2 Year Ended December 31, 2021 Customer relationships, beginning of period $ 1,794.2 $ (668.8) $ 1,125.4 Customer relationships obtained from acquisition of business 50.6 — 50.6 Amortization expense — (126.3) (126.3) Customer relationships, end of period $ 1,844.8 $ (795.1) $ 1,049.7
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2024 $ 127.6 2025 110.2 2026 106.3 2027 106.3 2028 106.3 Thereafter 236.9 Total $ 793.6

Related Party Disclosures (Tabl

Related Party Disclosures (Tables)	12 Months Ended
	Dec. 31, 2023
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: December 31, 2023 December 31, 2022 Accrued natural gas, NGLs, condensate, and crude oil purchases $ 0.3 $ 2.5 We recorded the following amounts (in millions) on our consolidated statements of operations related to our transactions with the Cedar Cove JV: Year Ended December 31, 2023 2022 2021 Midstream services revenue $ 2.5 $ 2.2 $ — Cost of sales (7.5) (28.2) (17.9)

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Assets and Liabilities, Lessee	Lease balances are recorded on the consolidated balance sheets as follows (in millions): Operating leases: December 31, 2023 December 31, 2022 Other assets, net $ 75.6 $ 69.5 Other current liabilities $ 28.2 $ 26.2 Other long-term liabilities $ 69.6 $ 66.2 Other lease information Weighted-average remaining lease term—Operating leases 7.7 years 8.7 years Weighted-average discount rate—Operating leases 5.3 % 4.7 %
Lease, Cost	The components of total lease expense are as follows (in millions): Year Ended December 31, 2023 2022 2021 Operating lease expense: Long-term operating lease expense $ 34.6 $ 28.2 $ 21.7 Short-term lease expense 41.3 34.3 17.5 Variable lease expense 18.6 18.8 15.6 Impairments — — 0.2 Total lease expense, before sublease income 94.5 81.3 55.0 Sublease income (1.8) (1.1) — Total lease expense, net of sublease income $ 92.7 $ 80.2 $ 55.0
Lessee, Operating Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of December 31, 2023 (in millions): Total 2024 2025 2026 2027 2028 Thereafter Undiscounted operating lease liability $ 123.8 $ 31.8 $ 24.4 $ 15.2 $ 9.1 $ 8.7 $ 34.6 Reduction due to present value (26.0) (4.3) (3.2) (2.3) (1.8) (1.4) (13.0) Operating lease liability $ 97.8 $ 27.5 $ 21.2 $ 12.9 $ 7.3 $ 7.3 $ 21.6
Finance Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of December 31, 2023 (in millions): Total 2024 2025 2026 2027 2028 Thereafter Undiscounted operating lease liability $ 123.8 $ 31.8 $ 24.4 $ 15.2 $ 9.1 $ 8.7 $ 34.6 Reduction due to present value (26.0) (4.3) (3.2) (2.3) (1.8) (1.4) (13.0) Operating lease liability $ 97.8 $ 27.5 $ 21.2 $ 12.9 $ 7.3 $ 7.3 $ 21.6

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Summary of Debt	As of December 31, 2023 and 2022, long-term debt consisted of the following (in millions): December 31, 2023 December 31, 2022 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt AR Facility due 2025 (1) 300.0 — 300.0 500.0 — 500.0 Revolving Credit Facility due 2027 (2) — — — 255.0 — 255.0 ENLK’s 4.40% Senior unsecured notes due 2024 97.9 — 97.9 97.9 — 97.9 ENLK’s 4.15% Senior unsecured notes due 2025 421.6 — 421.6 421.6 (0.1) 421.5 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.2) 490.8 491.0 (0.2) 490.8 ENLC’s 5.625% Senior unsecured notes due 2028 500.0 — 500.0 500.0 — 500.0 ENLC’s 5.375% Senior unsecured notes due 2029 498.7 — 498.7 498.7 — 498.7 ENLC’s 6.50% Senior unsecured notes due 2030 1,000.0 (2.7) 997.3 700.0 — 700.0 ENLK’s 5.60% Senior unsecured notes due 2044 350.0 (0.2) 349.8 350.0 (0.2) 349.8 ENLK’s 5.05% Senior unsecured notes due 2045 450.0 (5.0) 445.0 450.0 (5.2) 444.8 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,609.2 $ (8.2) 4,601.0 $ 4,764.2 $ (5.8) 4,758.4 Debt issuance cost (3) (32.1) (34.9) Less: Current maturities of long-term debt (4) (97.9) — Long-term debt, net of unamortized issuance cost $ 4,471.0 $ 4,723.5 ____________________________ (1) The effective interest rate was 6.4% and 5.3% at December 31, 2023 and 2022, respectively. (2) The effective interest rate was 6.5% at December 31, 2022. (3) Net of accumulated amortization of $20.0 million and $15.1 million at December 31, 2023 and 2022, respectively. (4) The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes as of December 31, 2023 are classified as “Current maturities of long-term debt” on the consolidated balance sheet as these notes mature on April 1, 2024. Issuance Maturity Date of Notes Early Redemption Date Basis Point Premium 2024 Notes April 1, 2024 Prior to January 1, 2024 25 Basis Points 2025 Notes June 1, 2025 Prior to March 1, 2025 30 Basis Points 2026 Notes July 15, 2026 Prior to April 15, 2026 50 Basis Points 2028 Notes January 15, 2028 Prior to July 15, 2027 50 Basis Points 2029 Notes June 1, 2029 Prior to March 1, 2029 50 Basis Points 2030 Notes September 1, 2030 Prior to March 1, 2030 50 Basis Points 2044 Notes April 1, 2044 Prior to October 1, 2043 30 Basis Points 2045 Notes April 1, 2045 Prior to October 1, 2044 30 Basis Points 2047 Notes June 1, 2047 Prior to December 1, 2046 40 Basis Points Activity related to the repurchases of ENLK’s senior unsecured notes from the settled debt tender offer consisted of the following (in millions): Year Ended Debt repurchased $ 700.0 Aggregate payments (705.3) Net discount on repurchased debt (1.0) Loss on extinguishment of debt $ (6.3) Year Ended Debt repurchased $ 23.1 Aggregate payments (22.5) Gain on extinguishment of debt $ 0.6
Schedule of Maturities of Long-term Debt	Maturities for the long-term debt as of December 31, 2023 are as follows (in millions): 2024 $ 97.9 2025 721.6 2026 491.0 2027 — 2028 500.0 Thereafter 2,798.7 Subtotal 4,609.2 Less: net discount (8.2) Less: debt issuance cost (32.1) Less: current maturities of long-term debt (97.9) Long-term debt, net of unamortized issuance cost $ 4,471.0

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax benefit (expense) are as follows (in millions): Year Ended December 31, 2023 2022 2021 Current income tax expense $ (0.7) $ (0.4) $ (0.8) Deferred income tax benefit (expense) (62.1) 95.3 (24.6) Income tax benefit (expense) $ (62.8) $ 94.9 $ (25.4)
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): Year Ended December 31, 2023 2022 2021 Expected income tax expense based on federal statutory tax rate $ (56.5) $ (55.9) $ (10.0) State income tax expense, net of federal benefit (7.2) (7.0) (1.4) Unit-based compensation (1) 7.7 0.7 (3.1) Statutory rate changes (2) — — (10.2) Change in valuation allowance (1.2) 151.6 1.7 Other (5.6) 5.5 (2.4) Total income tax benefit (expense) $ (62.8) $ 94.9 $ (25.4) ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of unit-based awards. (2)
Schedule of Deferred Tax Assets and Liabilities	Our deferred income tax assets and liabilities as of December 31, 2023 and 2022 are as follows (in millions): December 31, 2023 December 31, 2022 Deferred income tax assets: Federal net operating loss carryforward $ 627.2 $ 636.5 State net operating loss carryforward 77.2 77.6 Interest deduction limitation (1) 53.0 57.6 Other 2.1 2.4 Total deferred tax assets, gross 759.5 774.1 Valuation allowance (1.2) — Total deferred tax assets, net of valuation allowance 758.3 774.1 Deferred tax liabilities: Property, plant, equipment, and intangible assets (2) (862.5) (816.8) Total deferred tax liabilities (862.5) (816.8) Deferred tax liability, net $ (104.2) $ (42.7) ____________________________ (1) Related to book-to-tax differences between the allowable interest deduction amount under Section 163j of the Internal Revenue Code of 1986, as amended. (2) Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment .

Certain Provisions of the ENL_2

Certain Provisions of the ENLK Partnership Agreement (Tables)	12 Months Ended
	Dec. 31, 2023
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the years ended December 31, 2023, 2022, and 2021 is provided below: Declaration period PIK Distribution Cash distribution Date paid 2023 First Quarter of 2023 135,421 $ 15.2 May 12, 2023 Second Quarter of 2023 135,759 $ 15.3 August 11, 2023 Third Quarter of 2023 136,099 $ 15.3 November 10, 2023 Fourth Quarter of 2023 136,439 $ 15.3 February 9, 2024 2022 First Quarter of 2022 — $ 17.5 May 13, 2022 (2) Second Quarter of 2022 — $ 17.3 August 12, 2022 Third Quarter of 2022 — $ 17.3 November 14, 2022 Fourth Quarter of 2022 — $ 17.3 February 13, 2023 2021 First Quarter of 2021 150,871 $ 17.0 May 14, 2021 Second Quarter of 2021 151,248 $ 17.0 August 13, 2021 Third Quarter of 2021 151,626 $ 17.1 November 12, 2021 Fourth Quarter of 2021 — $ 19.2 February 11, 2022 (1) ____________________________ (1) In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022. (2) In January 2022, we paid $0.3 million of accrued distributions related to the first quarter of 2022 on redeemed Series B Preferred Units. The remaining distribution of $17.2 million related to the first quarter of 2022 was paid on May 13, 2022. Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period. A summary of the distribution activity relating to the Series C Preferred Units 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 2023 December 15, 2022 – March 14, 2023 8.846 % $ 8.4 March 15, 2023 March 15, 2023 – June 14, 2023 9.051 % $ 8.7 June 15, 2023 June 15, 2023 – September 14, 2023 9.618 % $ 9.3 September 15, 2023 September 15, 2023 - December 14, 2023 9.782 % $ 9.3 December 15, 2023 2022 December 15, 2021 – June 14, 2022 6.000 % $ 12.0 June 15, 2022 June 15, 2022 – December 14, 2022 6.000 % $ 11.4 December 15, 2022 2021 December 15, 2020 – June 14, 2021 6.000 % $ 12.0 June 15, 2021 June 15, 2021 – December 14, 2021 6.000 % $ 12.0 December 15, 2021 ____________________________ (1) Distributions on the Series C Preferred Units accrued and were cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. (2) The initial distribution rate for the Series C Preferred Units from the date of original issue through December 14, 2022 was 6.0% per year. Starting on December 15, 2022, distributions on the Series C Preferred Units accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to the floating rate of the three-month LIBOR plus a spread of 4.11%. 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%.
Schedule of Repurchase Agreements	A summary of the repurchase activity relating to the Series C Preferred Units is provided below: Transaction date Series C Preferred Units Repurchased Total Consideration (in millions) Percent Represented of Repurchased Preferred Units’ Par Value 2023 February 2023 4,500 $ 3.9 87 % November 2023 3,000 $ 2.7 90 % December 2023 7,000 $ 6.5 93 % 2022 October 2022 19,000 $ 15.2 80 % Date Board Action Authorized Amount November 2020 Authorization of common unit repurchase program $ 100 April 2021 Reauthorization of common unit repurchase program $ 100 January 2022 Reauthorization of common unit repurchase program and set amount available for repurchases for 2022 $ 100 July 2022 Increase in 2022 common unit repurchase program $ 100 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) Starting on February 15, 2022, the authorized amount includes repurchases of common units held by GIP. Refer to “Note 5—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): Year Ended December 31, 2023 2022 2021 Publicly held ENLC common units 11,530,962 11,630,351 6,091,001 ENLC common units held by GIP (1) 8,846,445 6,743,703 — Total ENLC common units 20,377,407 18,374,054 6,091,001 Aggregate cost for publicly held ENLC common units $ 134.5 $ 111.5 $ 40.1 Aggregate cost for ENLC common units held by GIP 98.3 63.5 — Excise tax on common unit repurchases $ 2.0 $ — $ — Total aggregate cost for ENLC common units $ 234.8 $ 175.0 $ 40.1 Average price paid per publicly held ENLC common unit (2) $ 11.67 $ 9.59 $ 6.59 Average price paid per ENLC common unit held by GIP (2)(3) $ 11.11 $ 9.42 $ — ____________________________ (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)

Members' Equity (Tables)

Members' Equity (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Summary of Repurchase Agreements	A summary of the repurchase activity relating to the Series C Preferred Units is provided below: Transaction date Series C Preferred Units Repurchased Total Consideration (in millions) Percent Represented of Repurchased Preferred Units’ Par Value 2023 February 2023 4,500 $ 3.9 87 % November 2023 3,000 $ 2.7 90 % December 2023 7,000 $ 6.5 93 % 2022 October 2022 19,000 $ 15.2 80 % Date Board Action Authorized Amount November 2020 Authorization of common unit repurchase program $ 100 April 2021 Reauthorization of common unit repurchase program $ 100 January 2022 Reauthorization of common unit repurchase program and set amount available for repurchases for 2022 $ 100 July 2022 Increase in 2022 common unit repurchase program $ 100 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) Starting on February 15, 2022, the authorized amount includes repurchases of common units held by GIP. Refer to “Note 5—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): Year Ended December 31, 2023 2022 2021 Publicly held ENLC common units 11,530,962 11,630,351 6,091,001 ENLC common units held by GIP (1) 8,846,445 6,743,703 — Total ENLC common units 20,377,407 18,374,054 6,091,001 Aggregate cost for publicly held ENLC common units $ 134.5 $ 111.5 $ 40.1 Aggregate cost for ENLC common units held by GIP 98.3 63.5 — Excise tax on common unit repurchases $ 2.0 $ — $ — Total aggregate cost for ENLC common units $ 234.8 $ 175.0 $ 40.1 Average price paid per publicly held ENLC common unit (2) $ 11.67 $ 9.59 $ 6.59 Average price paid per ENLC common unit held by GIP (2)(3) $ 11.11 $ 9.42 $ — ____________________________ (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)
Computation of Basic and Diluted Earnings per Limited Partner Unit	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): Year Ended December 31, 2023 2022 2021 Distributed earnings allocated to: Common units (1) $ 234.3 $ 221.3 $ 192.5 Unvested unit-based awards (1) 3.9 5.2 4.5 Total distributed earnings $ 238.2 $ 226.5 $ 197.0 Undistributed income (loss) allocated to: Common units $ (31.5) $ 131.7 $ (170.6) Unvested unit-based awards (0.5) 3.1 (4.0) Total undistributed income (loss) $ (32.0) $ 134.8 $ (174.6) Net income attributable to ENLC allocated to: Common units $ 202.8 $ 353.0 $ 21.9 Unvested unit-based awards 3.4 8.3 0.5 Total net income attributable to ENLC $ 206.2 $ 361.3 $ 22.4 Net income attributable to ENLC per unit: Basic $ 0.45 $ 0.76 $ 0.05 Diluted $ 0.44 $ 0.74 $ 0.05 ____________________________ (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): Year Ended December 31, 2023 2022 2021 Basic weighted average units outstanding: Weighted average common units outstanding 461.7 478.5 488.8 Diluted weighted average units outstanding: Weighted average basic common units outstanding 461.7 478.5 488.8 Dilutive effect of unvested restricted units 4.3 6.8 5.5 Total weighted average diluted common units outstanding 466.0 485.3 494.3
Summary of Distribution Activity	A summary of our distribution activity related to the ENLC common units for the years ended December 31, 2023, 2022, and 2021, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2023 First Quarter of 2023 $ 0.12500 May 12, 2023 Second Quarter of 2023 $ 0.12500 August 11, 2023 Third Quarter of 2023 $ 0.12500 November 10, 2023 Fourth Quarter of 2023 $ 0.13250 February 9, 2024 2022 First Quarter of 2022 $ 0.11250 May 13, 2022 Second Quarter of 2022 $ 0.11250 August 12, 2022 Third Quarter of 2022 $ 0.11250 November 14, 2022 Fourth Quarter of 2022 $ 0.12500 February 13, 2023 2021 First Quarter of 2021 $ 0.09375 May 14, 2021 Second Quarter of 2021 $ 0.09375 August 13, 2021 Third Quarter of 2021 $ 0.09375 November 12, 2021 Fourth Quarter of 2021 $ 0.11250 February 11, 2022

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Activity Related to Investments in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Year Ended December 31, 2023 2022 2021 GCF Contributions $ 24.6 $ 1.5 $ — Distributions $ (2.0) $ — $ (3.5) Equity in loss $ (4.4) $ (3.2) $ (9.1) Cedar Cove JV Distributions $ (0.5) $ (0.7) $ (0.4) Equity in loss $ (2.4) $ (1.9) $ (2.4) Matterhorn JV Contributions $ 43.5 $ 64.4 $ — Equity in loss $ (1.4) $ (0.5) $ — Total Contributions $ 68.1 $ 65.9 $ — Distributions $ (2.5) $ (0.7) $ (3.9) Equity in loss $ (8.2) $ (5.6) $ (11.5) The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2023 and 2022 (in millions): December 31, 2023 December 31, 2022 GCF $ 44.5 $ 26.3 Cedar Cove JV (1) (7.3) (4.4) Matterhorn JV 106.0 63.9 Total investment in unconsolidated affiliates $ 143.2 $ 85.8 ___________________________ (1)

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Amounts Recognized in Consolidated Financial Statements	Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Year Ended December 31, 2023 2022 2021 Cost of unit-based compensation charged to operating expense $ 3.7 $ 5.7 $ 6.6 Cost of unit-based compensation charged to general and administrative expense 15.5 24.7 18.7 Total unit-based compensation expense $ 19.2 $ 30.4 $ 25.3 Amount of related income tax benefit recognized in net income (1) $ 4.5 $ 7.1 $ 5.9 ____________________________ (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 8—Income Taxes.”
Summary of Restricted Incentive Unit Activity	A summary of the restricted incentive unit activity for the year ended December 31, 2023 is provided below: Year Ended December 31, 2023 Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 6,775,186 $ 5.89 Granted (1) 1,587,965 11.03 Vested (1)(2) (2,489,603) 5.96 Forfeited (427,568) 6.98 Unvested, end of period 5,445,980 $ 7.27 Aggregate intrinsic value, end of period (in millions) $ 66.2 ____________________________ (1) Restricted incentive units typically vest at the end of three years. (2)
Summary of Restricted Units' Aggregate Intrinsic Value	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 years ended December 31, 2023, 2022, and 2021 is provided below (in millions): Year Ended December 31, Restricted Incentive Units: 2023 2022 2021 Aggregate intrinsic value of units vested $ 30.5 $ 24.4 $ 5.6 Fair value of units vested $ 14.8 $ 19.0 $ 16.3
Summary of Grant-Date Fair Values	The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies: Performance Level Achieved ENLC TSR Vesting Percentage of the Tranche TSR Units Below Threshold Less than 25% 0% Threshold Equal to 25% 50% Target Equal to 50% 100% Maximum Greater than or Equal to 85% (1) 200% ____________________________ (1) The performance awards granted prior to 2023 achieved the maximum performance level if the ENLC TSR position relative to designated peer companies was greater than or equal to 75%. Performance Period Ended December 31, 2023 2022 2021 Performance Level Vesting Percentage of the Tranche CF Units Achieved DCF Achieved FCFAD Achieved FCFAD Below Threshold 0% Less than $801 million Less than $154 million Less than $205 million Threshold 50% Equal to $801 million Equal to $154 million Equal to $205 million Target 100% Equal to $932 million Equal to $202 million Equal to $256 million Maximum 200% Greater than or Equal to $1,123 million Greater than or Equal to $241 million Greater than or Equal to $300 million The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the Designated Peer Companies’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC among the Designated Peer Companies or Peer Companies, and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: Performance Units: March 2023 June 2022 March 2022 (1) January 2021 Grant-date fair value $ 11.67 $ 11.71 $ 11.90 $ 4.70 Beginning TSR price $ 10.40 $ 8.54 $ 8.83 $ 3.71 Risk-free interest rate 3.76 % 3.35 % 2.15 % 0.17 % Volatility factor 64.00 % 76.00 % 75.00 % 71.00 % ____________________________ (1) Excludes certain performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 performance units have a grant-date fair value of $8.90 and were scheduled to vest in February 2023. However, this award partially vested in October 2022 and is reflected in the “Vested” row of the summary of the performance units table below.
Summary of Performance Units	The following table presents a summary of the performance units: Year Ended December 31, 2023 Performance Units: Number of Units Weighted Average Grant-Date Fair Value Unvested, beginning of period 2,979,154 $ 6.44 Granted 420,128 11.67 Vested (1) (1,091,523) 8.30 Forfeited (71,015) 10.97 Unvested, end of period 2,236,744 $ 6.37 Aggregate intrinsic value, end of period (in millions) $ 27.2 ____________________________ (1) Vested units included 811,114 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 years ended December 31, 2023, 2022, and 2021 is provided below (in millions). Year Ended December 31, Performance Units: 2023 2022 2021 Aggregate intrinsic value of units vested $ 26.1 $ 20.4 $ 0.6 Fair value of units vested $ 9.1 $ 26.2 $ 4.4

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps are as follows (in millions): Year Ended December 31, 2023 2022 2021 Change in fair value of interest rate swaps $ 0.9 $ 1.9 $ 18.2 Tax expense (0.2) (0.5) (4.3) Unrealized gain on designated cash flow hedge $ 0.7 $ 1.4 $ 13.9 Interest expense (income) is recognized from accumulated other comprehensive income from the monthly settlement of our interest rate swaps and was included in our consolidated statements of operations as follows (in millions): Year Ended December 31, 2023 2022 2021 Interest expense (income) $ (4.5) $ 1.9 $ 18.3 The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity derivatives are as follows (in millions): Year Ended December 31, 2023 2022 2021 Change in fair value of derivatives $ (12.1) $ 40.2 $ (12.4) Realized gain (loss) on derivatives 32.8 (25.9) (146.7) Gain (loss) on derivative activity $ 20.7 $ 14.3 $ (159.1)
Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps	The fair value of derivative assets and liabilities related to the interest rate swaps are as follows (in millions): Year Ended December 31, 2023 2022 Fair value of derivative assets—current $ 3.3 $ — Fair value of derivative liabilities—long-term (2.4) — Net fair value of interest rate swaps $ 0.9 $ — The fair value of derivative assets and liabilities related to commodity derivatives are as follows (in millions): December 31, 2023 December 31, 2022 Fair value of derivative assets—current $ 73.6 $ 68.4 Fair value of derivative assets—long-term 27.0 2.9 Fair value of derivative liabilities—current (62.7) (42.9) Fair value of derivative liabilities—long-term (24.3) (2.7) Net fair value of commodity derivatives $ 13.6 $ 25.7
Notional Amount and Fair Value of Derivative Instruments	Set forth below are the summarized notional volumes and fair values of all instruments related to commodity derivatives that we held for price risk management purposes and the related physical offsets at December 31, 2023 (in millions, except volumes). The remaining term of the contracts extend no later than January 2028. December 31, 2023 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps MMgals (111.8) $ (0.8) NGL (long contracts) Swaps MMgals 58.0 1.1 Natural gas (short contracts) Swaps and futures Bbtu (145.8) 86.6 Natural gas (long contracts) Swaps and futures Bbtu 122.4 (75.5) Crude and condensate (short contracts) Swaps and futures MMbbls (7.4) 2.3 Crude and condensate (long contracts) Swaps and futures MMbbls 0.1 (0.1) Total fair value of commodity derivatives $ 13.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Derivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 December 31, 2023 December 31, 2022 Interest rate swaps (1) $ 0.9 $ — Commodity derivatives (2) $ 13.6 $ 25.7 ____________________________ (1) The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. (2)
Schedule of the Estimated Fair Value of Financial Instruments	Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): December 31, 2023 December 31, 2022 Carrying Value Fair Value Carrying Value Fair Value Long-term debt, including current maturities of long-term debt (1) $ 4,568.9 $ 4,427.0 $ 4,723.5 $ 4,385.9 Contingent consideration (2)(3) $ 6.7 $ 6.7 $ 5.5 $ 5.5 ____________________________ (1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance cost, net of accumulated amortization, of $32.1 million and $34.9 million as of December 31, 2023 and 2022, respectively. The respective fair values do not factor in debt issuance costs. (2) Consideration for the Amarillo Rattler Acquisition included a contingent component capped at $15.0 million and payable, if at all, between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. (3)

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Summary of Financial Information	Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian Louisiana Oklahoma North Texas Corporate Totals Year Ended December 31, 2023 Natural gas sales $ 453.4 $ 444.7 $ 184.5 $ 76.6 $ — $ 1,159.2 NGL sales (12.0) 3,031.2 8.5 (6.2) — 3,021.5 Crude oil and condensate sales 1,250.0 215.6 109.3 — — 1,574.9 Product sales 1,691.4 3,691.5 302.3 70.4 — 5,755.6 NGL sales—related parties 927.9 22.4 465.6 295.9 (1,711.8) — Crude oil and condensate sales—related parties — — — 10.5 (10.5) — Product sales—related parties 927.9 22.4 465.6 306.4 (1,722.3) — Gathering and transportation 114.6 79.9 236.8 203.9 — 635.2 Processing 60.1 1.6 144.4 123.4 — 329.5 NGL services — 87.3 — 0.2 — 87.5 Crude services 23.9 19.6 17.5 0.7 — 61.7 Other services 7.3 1.3 0.5 0.8 — 9.9 Midstream services 205.9 189.7 399.2 329.0 — 1,123.8 NGL services—related parties — — — 3.7 (3.7) — Midstream services—related parties — — — 3.7 (3.7) — Revenue from contracts with customers 2,825.2 3,903.6 1,167.1 709.5 (1,726.0) 6,879.4 Realized gain on derivatives 3.0 2.6 6.5 20.7 — 32.8 Change in fair value of derivatives (5.0) 4.1 (2.2) (9.0) — (12.1) Total revenues 2,823.2 3,910.3 1,171.4 721.2 (1,726.0) 6,900.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (2,205.5) (3,388.4) (645.6) (342.6) 1,726.0 (4,856.1) Adjusted gross margin 617.7 521.9 525.8 378.6 — 2,044.0 Operating expenses (221.3) (130.3) (103.8) (102.8) — (558.2) Segment profit 396.4 391.6 422.0 275.8 — 1,485.8 Depreciation and amortization (166.6) (151.3) (217.7) (115.8) (5.7) (657.1) Gross margin 229.8 240.3 204.3 160.0 (5.7) 828.7 Impairments — (20.7) — — — (20.7) Gain (loss) on disposition of assets 0.2 (2.0) 0.9 1.2 — 0.3 General and administrative — — — — (115.5) (115.5) Interest expense, net of interest income — — — — (271.7) (271.7) Loss from unconsolidated affiliate investments — — — — (8.2) (8.2) Other loss — — — — (0.1) (0.1) Income (loss) before non-controlling interest and income taxes $ 230.0 $ 217.6 $ 205.2 $ 161.2 $ (401.2) $ 412.8 Capital expenditures $ 267.3 $ 68.6 $ 69.2 $ 75.5 $ 6.2 $ 486.8 Permian Louisiana Oklahoma North Texas Corporate Totals Year Ended December 31, 2022 Natural gas sales $ 1,078.7 $ 1,128.4 $ 367.5 $ 139.0 $ — $ 2,713.6 NGL sales (1.5) 4,196.6 10.8 1.4 — 4,207.3 Crude oil and condensate sales 1,158.6 350.0 135.4 — — 1,644.0 Product sales 2,235.8 5,675.0 513.7 140.4 — 8,564.9 NGL sales—related parties 1,495.6 97.7 774.6 543.6 (2,911.5) — Crude oil and condensate sales—related parties — — 0.3 12.3 (12.6) — Product sales—related parties 1,495.6 97.7 774.9 555.9 (2,924.1) — Gathering and transportation 72.6 75.5 187.5 185.7 — 521.3 Processing 39.2 1.5 119.7 125.9 — 286.3 NGL services — 82.0 — 0.2 — 82.2 Crude services 21.4 33.3 14.9 0.7 — 70.3 Other services 0.8 1.6 (0.3) 0.7 — 2.8 Midstream services 134.0 193.9 321.8 313.2 — 962.9 NGL services—related parties — — — 1.6 (1.6) — Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 0.2 — — (0.2) — Midstream services—related parties — 0.2 0.1 1.6 (1.9) — Revenue from contracts with customers 3,865.4 5,966.8 1,610.5 1,011.1 (2,926.0) 9,527.8 Realized gain (loss) on derivatives (9.0) 2.9 (13.1) (6.7) — (25.9) Change in fair value of derivatives 9.6 7.7 5.6 17.3 — 40.2 Total revenues 3,866.0 5,977.4 1,603.0 1,021.7 (2,926.0) 9,542.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (3,280.3) (5,462.4) (1,124.4) (631.7) 2,926.0 (7,572.8) Adjusted gross margin 585.7 515.0 478.6 390.0 — 1,969.3 Operating expenses (200.2) (140.7) (90.9) (93.1) — (524.9) Segment profit 385.5 374.3 387.7 296.9 — 1,444.4 Depreciation and amortization (154.5) (156.5) (201.8) (121.1) (5.5) (639.4) Gross margin 231.0 217.8 185.9 175.8 (5.5) 805.0 Gain (loss) on disposition of assets 0.1 (13.8) 0.5 (4.8) — (18.0) General and administrative — — — — (125.2) (125.2) Interest expense, net of interest income — — — — (245.0) (245.0) Loss on extinguishment of debt — — — — (6.2) (6.2) Loss from unconsolidated affiliate investments — — — — (5.6) (5.6) Other income — — — — 0.8 0.8 Income (loss) before non-controlling interest and income taxes $ 231.1 $ 204.0 $ 186.4 $ 171.0 $ (386.7) $ 405.8 Capital expenditures $ 210.2 $ 33.7 $ 63.8 $ 22.8 $ 7.1 $ 337.6 Permian Louisiana Oklahoma North Texas Corporate Totals Year Ended December 31, 2021 Natural gas sales $ 609.4 $ 693.5 $ 213.4 $ 150.0 $ — $ 1,666.3 NGL sales 0.9 3,353.1 2.0 1.1 — 3,357.1 Crude oil and condensate sales 677.4 212.0 81.2 — — 970.6 Product sales 1,287.7 4,258.6 296.6 151.1 — 5,994.0 NGL sales—related parties 1,008.4 129.7 630.8 447.0 (2,215.9) — Crude oil and condensate sales—related parties — — 0.1 7.1 (7.2) — Product sales—related parties 1,008.4 129.7 630.9 454.1 (2,223.1) — Gathering and transportation 46.8 64.7 186.9 157.0 — 455.4 Processing 29.1 2.4 98.7 108.3 — 238.5 NGL services — 82.6 — 0.3 — 82.9 Crude services 18.4 39.3 12.8 0.7 — 71.2 Other services 0.2 1.7 0.6 0.5 — 3.0 Midstream services 94.5 190.7 299.0 266.8 — 851.0 Crude services—related parties — — 0.3 — (0.3) — Other services—related parties — 2.4 — — (2.4) — Midstream services—related parties — 2.4 0.3 — (2.7) — Revenue from contracts with customers 2,390.6 4,581.4 1,226.8 872.0 (2,225.8) 6,845.0 Realized loss on derivatives (75.6) (42.3) (22.6) (6.2) — (146.7) Change in fair value of derivatives (7.7) 0.7 — (5.4) — (12.4) Total revenues 2,307.3 4,539.8 1,204.2 860.4 (2,225.8) 6,685.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,996.1) (4,091.2) (796.6) (531.8) 2,225.8 (5,189.9) Adjusted gross margin 311.2 448.6 407.6 328.6 — 1,496.0 Operating expenses (81.5) (123.7) (80.0) (77.7) — (362.9) Segment profit 229.7 324.9 327.6 250.9 — 1,133.1 Depreciation and amortization (139.9) (141.0) (204.3) (114.3) (8.0) (607.5) Gross margin 89.8 183.9 123.3 136.6 (8.0) 525.6 Impairments — (0.6) — — (0.2) (0.8) Gain on disposition of assets — 1.2 — 0.3 — 1.5 General and administrative — — — — (107.8) (107.8) Interest expense, net of interest income — — — — (238.7) (238.7) Loss from unconsolidated affiliate investments — — — — (11.5) (11.5) Income (loss) before non-controlling interest and income taxes $ 89.8 $ 184.5 $ 123.3 $ 136.9 $ (366.2) $ 168.3 Capital expenditures $ 141.6 $ 9.3 $ 30.4 $ 11.9 $ 2.8 $ 196.0
Schedule of Segment Assets	The table below represents information about segment assets as of December 31, 2023 and 2022 (in millions): Segment Identifiable Assets: December 31, 2023 December 31, 2022 Permian $ 2,813.6 $ 2,661.4 Louisiana 2,031.8 2,310.7 Oklahoma 2,275.8 2,420.4 North Texas 1,017.7 1,094.6 Corporate (1) 189.7 163.9 Total identifiable assets $ 8,328.6 $ 8,651.0 ____________________________ (1)

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2023
Supplemental Cash Flow Elements [Abstract]
Summary of Non-Cash Financing Activities	The following schedule summarizes cash paid for interest, cash paid (refunded) for income taxes, cash paid for operating leases included in cash flows from operating activities, non-cash investing activities, and non-cash financing activities for the periods presented (in millions): Year Ended December 31, Supplemental disclosures of cash flow information: 2023 2022 2021 Cash paid for interest $ 266.9 $ 221.1 $ 208.8 Cash paid for income taxes $ 1.6 $ 0.7 $ 0.3 Cash paid for operating leases included in cash flows from operating activities $ 35.1 $ 30.5 $ 24.6 Non-cash investing activities: Non-cash accrual of property and equipment $ 41.1 $ 4.2 $ 12.0 Non-cash right-of-use assets obtained in exchange for operating lease liabilities $ 36.5 $ 33.4 $ 18.7 Non-cash acquisitions $ — $ 1.3 $ 16.9 Non-cash financing activities: Redemption of mandatorily redeemable non-controlling interest $ — $ (6.5) $ —

Other Information (Tables)

Other Information (Tables)	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Schedule of Other Current Assets	The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: December 31, 2023 December 31, 2022 Product inventory $ 46.4 $ 147.1 Prepaid expenses and other 19.0 19.5 Other current assets $ 65.4 $ 166.6
Schedule of Other Current Liabilities	Other current liabilities: December 31, 2023 December 31, 2022 Accrued interest $ 63.4 $ 57.6 Accrued wages and benefits, including taxes 23.2 38.1 Accrued ad valorem taxes 33.3 32.0 Accrued settlement of mandatorily redeemable non-controlling interest (1) — 10.5 Capital expenditure accruals 64.6 23.4 Short-term lease liability 28.2 26.2 Operating expense accruals 21.5 18.5 Other 44.3 23.3 Other current liabilities $ 278.5 $ 229.6 ____________________________ (1) In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries.

Organization and Nature of Bu_2

Organization and Nature of Business (Details)	12 Months Ended
	Dec. 31, 2023 Bcf / d fractionator processingPlant mi bbl
Related Party Transaction [Line Items]
Number of miles of pipeline | mi	13,600
Number of natural gas processing plants | processingPlant	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	46.20%

Significant Accounting Polici_4

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Allowance for doubtful accounts receivable		$ 0	$ 0.1
Environmental remediation expense		0	0	$ 0
Debt issuance costs, noncurrent, net		32.1	34.9
Payment to redeem mandatorily redeemable non-controlling interest	$ 10.5	$ 10.5	0	$ 0
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Intangible asset, useful life		10 years
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Intangible asset, useful life		20 years
EnLink Midstream Partners, LP
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gas balancing payable		$ 6.3	17.3
Gas balancing receivable		$ 8	$ 20.2
Delaware Basin JV | NPG
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Noncontrolling interest, ownership percentage by parent		49.90%
Ascension JV | Marathon Petroleum Corporation
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Noncontrolling interest, ownership percentage by parent		50%

Significant Accounting Polici_5

Significant Accounting Policies - Summary of Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1,633.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 145
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 126.2
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 126.6
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 105.9
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 97.1
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1,032.9
Revenue, remaining performance obligation, expected timing of satisfaction, period

Significant Accounting Polici_6

Significant Accounting Policies - Components of Property and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property and equipment	$ 11,544.2	$ 11,330.5
Accumulated depreciation	(5,137.2)	(4,774.5)
Property and equipment, net of accumulated depreciation	6,407	6,556
Transmission assets
Property, Plant and Equipment [Line Items]
Property and equipment	$ 1,459.5	1,452
Transmission assets | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Transmission assets | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Gathering systems
Property, Plant and Equipment [Line Items]
Property and equipment	$ 5,472.4	5,370
Gathering systems | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Gathering systems | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Natural gas processing plants and fractionation facilities
Property, Plant and Equipment [Line Items]
Property and equipment	$ 4,279.1	4,237.8
Natural gas processing plants and fractionation facilities | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Natural gas processing plants and fractionation facilities | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Other property and equipment
Property, Plant and Equipment [Line Items]
Property and equipment	$ 90.1	165
Other property and equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Other property and equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Construction in process
Property, Plant and Equipment [Line Items]
Property and equipment	$ 243.1	$ 105.7

Significant Accounting Polici_7

Significant Accounting Policies - (Gain) Loss on Disposition of Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Net book value of assets disposed	$ 72.9	$ 30.8	$ 3.3
Proceeds from sales	(73.1)	(12.8)	(4.8)
Insurance recoveries	(0.1)	0	0
(Gain) loss on disposition of assets	$ (0.3)	$ 18	$ (1.5)

Significant Accounting Polici_8

Significant Accounting Policies - Property and Equipement Impairment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Property and equipment impairment	$ 20.7	$ 0	$ 0.6

Significant Accounting Polici_9

Significant Accounting Policies - Schedule of Revenue Concentration Risk (Details) - Customer Concentration Risk - Sales Revenue, Net	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Dow Hydrocarbons and Resources LLC
Concentration Risk [Line Items]
Concentration risk	10.40%	14.20%	14.50%
Marathon Petroleum Corporation
Concentration Risk [Line Items]
Concentration risk	19.30%	14.70%	13.40%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Narrative (Details)							6 Months Ended	12 Months Ended
	Nov. 03, 2023 USD ($)	Nov. 01, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 19, 2022 USD ($)	Jul. 01, 2022 USD ($) MMcf / d plant mi	Apr. 30, 2021 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2023 USD ($) Bcf / d mi	Dec. 31, 2022 USD ($)	Apr. 30, 2022 USD ($)
Business Acquisition [Line Items]
Number of miles of pipeline | mi								13,600
Amount of processing capacity | Bcf / d								5.8
Disposal Group, Disposed of by Sale, Not Discontinued Operations | ORV Crude Assets
Business Acquisition [Line Items]
Cash consideration	$ 9,800,000	$ 59,200,000
Additional payment		$ 500,000
Consideration term		3 years
Amarillo Rattler, LLC
Business Acquisition [Line Items]
Payments to acquire businesses						$ 50,000,000
Installment payable						10,000,000
Business combination, maximum earnout						$ 15,000,000				$ 15,000,000
Crestwood Gas Services Operating LLC
Business Acquisition [Line Items]
Payments to acquire businesses					$ 275,000,000
Working capital					$ 14,500,000
Number of miles of pipeline | mi					400
Number of processing plants | plant					3
Amount of processing capacity | MMcf / d					425
Direct transaction costs recognized as expense									$ 400,000
Recognized revenue							$ 39,600,000
Net gain (loss) related to assets acquired							24,100,000
Central Oklahoma Acquisition
Business Acquisition [Line Items]
Payments to acquire businesses				$ 95,800,000
Working capital				$ 5,100,000
Contingent consideration			$ 1,300,000				$ 1,300,000		1,300,000
Number of miles of pipeline | mi					900
Number of processing plants | plant					2
Amount of processing capacity | MMcf / d					280
Direct transaction costs recognized as expense								$ 300,000	$ 500,000
Recognized revenue			1,700,000
Net gain (loss) related to assets acquired			$ 600,000

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Fair Value of Assets Received and Liabilities Assumed (Details) - USD ($) $ in Millions	Jul. 01, 2022	Apr. 30, 2021
Assets acquired:
Intangible assets		$ 50.6
Other assets, net		0.6
Liabilities assumed:
Other long-term liabilities		(0.6)
Amarillo Rattler, LLC
Consideration
Cash (including working capital payment)		50.6
Installment payable		10
Contingent consideration fair value		6.9
Total consideration		67.5
Assets acquired:
Current assets		1.4
Property and equipment		16.3
Liabilities assumed:
Current liabilities		(0.8)
Net assets acquired		67.5
Cash acquired		1.3
Crestwood Gas Services Operating LLC
Consideration
Cash (including working capital payment)	$ 289.5
Assets acquired:
Current assets	17.3
Property and equipment	275
Liabilities assumed:
Current liabilities	(2.8)
Net assets acquired	$ 289.5
Central Oklahoma Acquisition
Consideration
Cash (including working capital payment)		100.9
Contingent consideration fair value		1.3
Total consideration		102.2
Assets acquired:
Current assets		6
Property and equipment		97.1
Other assets, net		0.9
Liabilities assumed:
Current liabilities		(1.4)
Other long-term liabilities		(0.4)
Net assets acquired		$ 102.2

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Contingent Consideration (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Contingent consideration liability, beginning of period	$ 5.5	$ 6.9	$ 0
Contingent consideration liability recorded upon acquisition	$ 0	$ 1.3	$ 6.9
Fair Value, Liability, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	General and Administrative Expense	General and Administrative Expense	General and Administrative Expense
Change in fair value	$ 1.2	$ (2.7)	$ 0
Contingent consideration liability, ending of period	6.7	5.5	6.9
Amarillo Rattler, LLC
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Contingent consideration liability, beginning of period	4.2	6.9	0
Contingent consideration liability recorded upon acquisition	0	0	6.9
Change in fair value	0.6	(2.7)	0
Contingent consideration liability, ending of period	4.8	4.2	6.9
Central Oklahoma Acquisition
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Contingent consideration liability, beginning of period	1.3	0	0
Contingent consideration liability recorded upon acquisition	0	1.3	0
Change in fair value	0.6	0	0
Contingent consideration liability, ending of period	$ 1.9	$ 1.3	$ 0

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Pro Forma (Details) - Crestwood Gas Services Operating LLC - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Pro forma total revenues	$ 9,630.4	$ 6,782.9
Pro forma net income	$ 534.3	$ 157.5

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details)	Dec. 31, 2023
Minimum
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	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 of Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Finite-lived Intangible Assets [Roll Forward]
Accumulated amortization, beginning of period	$ (923.6)
Customer relationships obtained from acquisition of business			$ 50.6
Accumulated amortization, end of period	(1,051.2)	$ (923.6)
EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Customer relationships, end of period, net	793.6
Customer Relationships | EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Customer relationships, beginning of period, gross	1,844.8	1,844.8	1,794.2
Accumulated amortization, beginning of period	(923.6)	(795.1)	(668.8)
Customer relationships, beginning of period, net	921.2	1,049.7	1,125.4
Amortization expense	(127.6)	(128.5)	(126.3)
Customer relationships, end of period, gross	1,844.8	1,844.8	1,844.8
Accumulated amortization, end of period	(1,051.2)	(923.6)	(795.1)
Customer relationships, end of period, net	$ 793.6	$ 921.2	$ 1,049.7

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) - EnLink Midstream Partners, LP $ in Millions	Dec. 31, 2023 USD ($)
Finite-Lived Intangible Assets [Line Items]
2024	$ 127.6
2025	110.2
2026	106.3
2027	106.3
2028	106.3
Thereafter	236.9
Total	$ 793.6

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 16, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Accrued natural gas, NGLs, condensate, and crude oil purchases		$ 126.5	$ 126.9
Midstream services revenue		6,879.4	9,527.8	$ 6,845
Cost of sales		(4,856.1)	(7,572.8)	(5,189.9)
Subsequent Event
Related Party Transaction [Line Items]
Repurchase agreement renewal term	1 year
Midstream services
Related Party Transaction [Line Items]
Midstream services revenue		1,123.8	962.9	851
Product sales—related parties | Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Accrued natural gas, NGLs, condensate, and crude oil purchases		2.5	0.3
Cost of sales		(7.5)	(28.2)	(17.9)
Product sales—related parties | Cedar Cove Joint Venture | Midstream services
Related Party Transaction [Line Items]
Midstream services revenue		$ 2.5	2.2	$ 0
CyrusOne
Related Party Transaction [Line Items]
Related party transactions			$ 0.2

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Lease liability	$ 97.8
Right-of-use assets	75.6	$ 69.5
Office Lease
Lessee, Lease, Description [Line Items]
Lease liability	40.4	46.2
Right-of-use assets	20.7	24.2
Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Lease liability	41.7	30.6
Right-of-use assets	42.5	33
Land
Lessee, Lease, Description [Line Items]
Lease liability	15.7	15.6
Right-of-use assets	$ 12.4	$ 12.3
Minimum | Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Maximum | Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Term of contract	3 years

Leases - Leases Balances on Con

Leases - Leases Balances on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating leases:
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Other assets, net	$ 75.6	$ 69.5
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities
Other current liabilities	$ 28.2	$ 26.2
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Other long-term liabilities	$ 69.6	$ 66.2
Other lease information
Weighted-average remaining lease term—Operating leases	7 years 8 months 12 days	8 years 8 months 12 days
Weighted-average discount rate—Operating leases	5.30%	4.70%

Leases - Components of Total Le

Leases - Components of Total Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating lease expense:
Long-term operating lease expense	$ 34.6	$ 28.2	$ 21.7
Short-term lease expense	41.3	34.3	17.5
Variable lease expense	18.6	18.8	15.6
Impairments	0	0	0.2
Operating Lease, Cost	94.5	81.3	55
Sublease income	(1.8)	(1.1)	0
Total lease expense, net of sublease income	$ 92.7	$ 80.2	$ 55

Leases - Maturity (Details)

Leases - Maturity (Details) $ in Millions	Dec. 31, 2023 USD ($)
Undiscounted operating lease liability
Total	$ 123.8
2024	31.8
2025	24.4
2026	15.2
2027	9.1
2028	8.7
Thereafter	34.6
Reduction due to present value
Total	(26)
2024	(4.3)
2025	(3.2)
2026	(2.3)
2027	(1.8)
2028	(1.4)
Thereafter	(13)
Operating Lease, Liability [Abstract]
Total	97.8
2024	27.5
2025	21.2
2026	12.9
2027	7.3
2028	7.3
Thereafter	$ 21.6

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument
Outstanding Principal	$ 4,609.2	$ 4,764.2
Premium (Discount)	(8.2)	(5.8)
Long-Term Debt	4,601	4,758.4
Debt issuance costs	(32.1)	(34.9)
Less: current maturities of long-term debt	(97.9)	0
Long-term debt, net of unamortized issuance cost	4,471	4,723.5
Debt issuance cost accumulated amortization	20	15.1
AR Facility due 2025
Debt Instrument
Outstanding Principal	300	500
Premium (Discount)	0	0
Long-Term Debt	$ 300	$ 500
Effective interest rate	6.40%	5.30%
Credit Facility Due 2024
Debt Instrument
Outstanding Principal	$ 0	$ 255
Premium (Discount)	0	0
Long-Term Debt	$ 0	$ 255
Effective interest rate		6.50%
4.40% Senior Notes due 2024
Debt Instrument
Stated interest rate	4.40%
Outstanding Principal	$ 97.9	$ 97.9
Premium (Discount)	0	0
Long-Term Debt	$ 97.9	97.9
4.15% Senior Notes due 2025
Debt Instrument
Stated interest rate	4.15%
Outstanding Principal	$ 421.6	421.6
Premium (Discount)	0	(0.1)
Long-Term Debt	$ 421.6	421.5
4.85 Senior Unsecured Notes Due 2026
Debt Instrument
Stated interest rate	4.85%
Outstanding Principal	$ 491	491
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 490.8	490.8
5.625% Senior unsecured notes due 2028
Debt Instrument
Stated interest rate	5.625%
Outstanding Principal	$ 500	500
Premium (Discount)	0	0
Long-Term Debt	$ 500	500
5.375% Senior unsecured notes due 2029
Debt Instrument
Stated interest rate	5.375%
Outstanding Principal	$ 498.7	498.7
Premium (Discount)	0	0
Long-Term Debt	$ 498.7	498.7
6.50% Senior unsecured notes due 2030
Debt Instrument
Stated interest rate	6.50%
Outstanding Principal	$ 1,000	700
Premium (Discount)	(2.7)	0
Long-Term Debt	$ 997.3	700
5.6% Senior Notes due 2044
Debt Instrument
Stated interest rate	5.60%
Outstanding Principal	$ 350	350
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 349.8	349.8
5.05 Senior Notes due 2045
Debt Instrument
Stated interest rate	5.05%
Outstanding Principal	$ 450	450
Premium (Discount)	(5)	(5.2)
Long-Term Debt	$ 445	444.8
Senior Unsecured Notes, 5.45%, Due 2047
Debt Instrument
Stated interest rate	5.45%
Outstanding Principal	$ 500	500
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9

Long-Term Debt - Schedule of Ma

Long-Term Debt - Schedule of Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
2024	$ 97.9
2025	721.6
2026	491
2027	0
2028	500
Thereafter	2,798.7
Subtotal	4,609.2	$ 4,764.2
Less: net discount	(8.2)	(5.8)
Less: debt issuance cost	(32.1)	(34.9)
Less: current maturities of long-term debt	(97.9)	0
Long-term debt, net of unamortized issuance cost	$ 4,471	$ 4,723.5

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)								12 Months Ended
	Dec. 31, 2023 USD ($)	Apr. 03, 2023 USD ($)	Aug. 31, 2022 USD ($)	Aug. 01, 2022	Jun. 03, 2022 USD ($)	Jun. 02, 2022 USD ($)	Dec. 11, 2018 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 14, 2020
Debt Instrument
Loss on extinguishment of debt								$ 0	$ 6,200,000	$ 0
Increase in accounts receivable due to consolidation								$ 629,300,000
Repurchase price as a percent of principal	101%							101%
Outstanding Principal	$ 4,609,200,000							$ 4,609,200,000	4,764,200,000
Proceeds from issuance of long-term debt								2,843,400,000	4,911,500,000	1,234,500,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity	404,200,000							404,200,000	$ 500,000,000	$ 500,000,000
Drawn fee percentage				0.90%					0.90%	0.90%
Long-term line of credit	$ 300,000,000							300,000,000
Secured Overnight Financing Rate (SOFR) | Line of Credit | Asset-backed Securities
Debt Instrument
Variable rate	0.10%
ENLK Credit Facility
Debt Instrument
Loss on extinguishment of debt					$ 500,000
Additional amount available (not to exceed)					1,400,000,000		$ 1,750,000,000
Modification limit					50,000,000
Financing receivables					$ 500,000,000	$ 350,000,000
Basis spread on variable rate, adjustment limit					0.05%
Commitment fee percentage, adjustment limit					0.02%
Fair value of amount outstanding	$ 0							0
ENLK Credit Facility | Letter of Credit | ENLC
Debt Instrument
Fair value of amount outstanding	26,700,000							$ 26,700,000
ENLK Credit Facility | Secured Overnight Financing Rate (SOFR) | Line of Credit | EnLink Midstream Partners, LP | Variable Rate Component One
Debt Instrument
Variable rate								0.10%
ENLK Credit Facility | LIBOR | Minimum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate								1.125%
ENLK Credit Facility | LIBOR | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate								2%
ENLK Credit Facility | Base Rate | Line of Credit | EnLink Midstream Partners, LP | Variable Rate Component Two
Debt Instrument
Variable rate								0.50%
4.15% Senior Notes due 2025
Debt Instrument
Outstanding Principal	$ 421,600,000							$ 421,600,000	$ 421,600,000
Stated interest rate	4.15%							4.15%
4.40% Senior Notes due 2024
Debt Instrument
Outstanding Principal	$ 97,900,000							$ 97,900,000	$ 97,900,000
Stated interest rate	4.40%							4.40%
Unsecured Debt
Debt Instrument
Percentage price of debt issued											100%
Debt repurchased		$ 700,000,000	$ 700,000,000
Proceeds from issuance of long-term debt			693,000,000
Repayments of debt			705,300,000
Debt tender premium			21,000,000
Debt discount			$ 15,700,000
Unsecured Debt | ENLK Credit Facility | Minimum
Debt Instrument
Conditional acquisition purchase price (or more)								$ 50,000,000
Unsecured Debt | ENLK Credit Facility | Maximum
Debt Instrument
Consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio	5.5							5.5
Unsecured Debt | ENLK Credit Facility | Eurodollar
Debt Instrument
Variable rate								1%
Unsecured Debt | Revolviing Credit Facility Unsecured
Debt Instrument
Consolidated indebtedness to consolidated EBITDA, ratio							5
Unsecured Debt | Revolviing Credit Facility Unsecured | Eurodollar
Debt Instrument
Variable rate								1%
Unsecured Debt | Revolviing Credit Facility Unsecured | Eurodollar | Minimum
Debt Instrument
Variable rate								0.125%
Unsecured Debt | 6.50% Senior Notes due 2030
Debt Instrument
Repurchase price as a percent of principal		99%	100%
Outstanding Principal		$ 300,000,000	$ 700,000,000
Stated interest rate		6.50%	6.50%
Unsecured Debt | 4.15% Senior Notes due 2025
Debt Instrument
Proceeds from issuance of long-term debt		$ 294,500,000	$ 295,600,000
Unsecured Debt | 4.40% Senior Notes due 2024
Debt Instrument
Proceeds from issuance of long-term debt			$ 404,400,000
Letter of Credit | Revolviing Credit Facility Unsecured
Debt Instrument
Percentage of letter of credits guaranteed	105%							105%

Long-Term Debt - Summary of Red

Long-Term Debt - Summary of Redemption Provision Terms (Details) - EnLink Midstream Partners, LP - Treasury Rate	12 Months Ended
	Dec. 31, 2023
4.4% Senior Notes due 2024
Debt Instrument
Redemption premium, percentage	25%
4.15% Senior Notes due 2025
Debt Instrument
Redemption premium, percentage	30%
4.85 Senior Unsecured Notes Due 2026
Debt Instrument
Redemption premium, percentage	50%
5.625% Senior unsecured notes due 2028
Debt Instrument
Redemption premium, percentage	50%
5.375% Senior unsecured notes due 2029
Debt Instrument
Redemption premium, percentage	50%
6.50% Senior unsecured notes due 2030
Debt Instrument
Redemption premium, percentage	50%
5.6% Senior Notes due 2044
Debt Instrument
Redemption premium, percentage	30%
5.05 Senior Notes due 2045
Debt Instrument
Redemption premium, percentage	30%
Senior Unsecured Notes, 5.45%, Due 2047
Debt Instrument
Redemption premium, percentage	40%

Long-Term Debt - Senior Unsecur

Long-Term Debt - Senior Unsecured Notes Repurchases (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Senior Unsecured Notes, Tender Offer
Debt Instrument
Debt repurchased	$ 700
Aggregate payments	(705.3)
Net discount on repurchased debt	(1)
Gain (loss) on extinguishment of debt	(6.3)
Senior Unsecured Notes, Open Market Transactions
Debt Instrument
Debt repurchased	23.1
Aggregate payments	(22.5)
Gain (loss) on extinguishment of debt	$ 0.6

Income Taxes - Components of Th

Income Taxes - Components of The Provision For Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.7)	$ (0.4)	$ (0.8)
Deferred income tax benefit (expense)	(62.1)	95.3	(24.6)
Income tax benefit (expense)	$ (62.8)	$ 94.9	$ (25.4)

Income Taxes - Book Income Reco

Income Taxes - Book Income Reconciliation To Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax expense based on federal statutory tax rate	$ (56.5)	$ (55.9)	$ (10)
State income tax expense, net of federal benefit	(7.2)	(7)	(1.4)
Unit-based compensation	7.7	0.7	(3.1)
Statutory rate changes	0	0	(10.2)
Change in valuation allowance	1.2	(151.6)	(1.7)
Other	(5.6)	5.5	(2.4)
Income tax benefit (expense)	$ (62.8)	$ 94.9	(25.4)
Oklahoma
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Deferred state income tax expense (benefit)			7.6
Louisiana
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Deferred state income tax expense (benefit)			$ 2.6

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred income tax assets:
Federal net operating loss carryforward	$ 627.2	$ 636.5
State net operating loss carryforward	77.2	77.6
Interest deduction limitation	53	57.6
Other	2.1	2.4
Total deferred tax assets, gross	759.5	774.1
Valuation allowance	(1.2)	0
Total deferred tax assets, net of valuation allowance	758.3	774.1
Deferred tax liabilities:
Property, plant, equipment, and intangible assets	(862.5)	(816.8)
Total deferred tax liabilities	(862.5)	(816.8)
Deferred tax liability, net	$ (104.2)	$ (42.7)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Line Items]
Change in valuation allowance	$ (1,200,000)	$ 151,600,000	$ 1,700,000
Unrecognized tax benefits	0	0
Excise tax on common unit repurchases	2,000,000	$ 0	$ 0
Domestic Tax Authority
Income Taxes [Line Items]
Operating loss carryforwards	3,000,000,000
Deferred tax assets, operating loss carryforwards, domestic	627,200,000
Operating loss carryforwards, amount carried indefinitely	2,800,000,000
Operating loss carryforwards, amount carried for a maximum of twenty years	200,000,000
State and Local Jurisdiction
Income Taxes [Line Items]
Operating loss carryforwards	1,600,000,000
Deferred tax assets, operating loss carryforwards, domestic	$ 77,200,000

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative (Details) $ / shares in Units, $ in Millions					1 Months Ended								12 Months Ended
	Sep. 08, 2023	Sep. 07, 2023	Dec. 15, 2022 $ / shares	Jan. 25, 2019	Dec. 31, 2023 USD ($) shares	Nov. 30, 2023 USD ($) shares	Feb. 28, 2023 USD ($) shares	Oct. 31, 2022 USD ($) shares	Jan. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares	Sep. 30, 2017 $ / shares shares	Jan. 31, 2016 $ / shares shares	Dec. 31, 2023 $ / shares shares	Dec. 31, 2022 shares
Partnership agreement
Common units conversion ratio				1.15
Series B Preferred Units
Partnership agreement
Stock redeemed during period (in shares)									3,333,334	3,300,330
Redemption of Series B Preferred Units | $									$ 50.5	$ 50
Percent Represented of Repurchased Preferred Units’ Par Value													101%
Series B Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)					54,575,638								54,575,638	54,168,359
Preferred units, outstanding (in shares)					54,575,638								54,575,638	54,168,359
Partners' capital account, units, sold in private placement (in shares)												50,000,000
Shares issued, price per share (in dollars per share) | $ / shares												$ 15
Annual rate on issue price													0.25%
Annual rate on issue price payable in cash	31.875%	28.125%											28.125%
Price payable, overage (in dollars per unit) | $ / shares													$ 6.79
Series C Preferred Units
Partnership agreement
Stock redeemed during period (in shares)					7,000	3,000	4,500	19,000
Redemption of Series B Preferred Units | $					$ 6.5	$ 2.7	$ 3.9	$ 15.2
Percent Represented of Repurchased Preferred Units’ Par Value					93%	90%	87%	80%
Partners capital account, redemption price (in dollars per share) | $ / shares			$ 1,000
Series C Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)					366,500								366,500	381,000
Preferred units, outstanding (in shares)					366,500								366,500	381,000
Shares issued, price per share (in dollars per share) | $ / shares											$ 1,000
Partners' capital account, units, sold in public offering (in shares)											400,000
Partners capital account, redemption price (in dollars per share) | $ / shares			$ 1,000
Partners' capital account, redemption period following review or appeal			120 days
Partners' capital account, redemption price following review or appeal (in dollars per share) | $ / shares			$ 1,020
Limited Partner | Series B Preferred Units
Partnership agreement
Partners' capital, conversion obligation period of consecutive trading days													30 days
Partners' capital, average trading price, number of trading days													2 days
Percent of issue price													150%

Certain Provisions of the ENL_4

Certain Provisions of the ENLK Partnership Agreement - Summary of Distribution (Details) - USD ($) $ / shares in Units, $ in Millions					1 Months Ended		3 Months Ended																	6 Months Ended
	Sep. 15, 2023	Dec. 15, 2022	May 13, 2022	Feb. 11, 2022	Jan. 31, 2022	Dec. 31, 2021	Mar. 14, 2024	Dec. 31, 2023	Dec. 14, 2023	Sep. 30, 2023	Sep. 14, 2023	Jun. 30, 2023	Jun. 14, 2023	Mar. 31, 2023	Mar. 14, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 14, 2022	Jun. 14, 2022	Dec. 14, 2021	Jun. 14, 2021
Series B Preferred Units | Limited Partner
Partnership agreement
PIK distributions (in shares)								136,439		136,099		135,759		135,421		0	0	0	0	0	151,626	151,248	150,871
Cash distribution (in millions)								$ 15.3		$ 15.3		$ 15.3		$ 15.2		$ 17.3	$ 17.3	$ 17.3	$ 17.5	$ 19.2	$ 17.1	$ 17	$ 17
Series B Preferred Units | Limited Partner | Distribution, Tranche One
Partnership agreement
Dividends, preferred stock				$ 17.3	$ 1	$ 0.9
Series B Preferred Units | Limited Partner | Distribution, Tranche Two
Partnership agreement
Dividends, preferred stock			$ 17.2		$ 0.3
Series C Preferred Units
Partnership agreement
Cash distribution (in millions)									$ 9.3		$ 9.3		$ 8.7		$ 8.4									$ 11.4	$ 12	$ 12	$ 12
Distribution rate per unit	0.26161%	6%							9.782%		9.618%		9.051%		8.846%									6%	6%	6%	6%
Partners capital account, redemption price (in dollars per share)		$ 1,000
Partners' capital account, distributions, variable floating rate percentage	4.11%	4.11%
Series C Preferred Units | Forecast
Partnership agreement
Cash distribution (in millions)							$ 9
Distribution rate per unit							9.749%

Certain Provisions of the ENL_5

Certain Provisions of the ENLK Partnership Agreement - Repurchases (Details) - Series C Preferred Units - USD ($) $ in Millions	1 Months Ended
	Dec. 31, 2023	Nov. 30, 2023	Feb. 28, 2023	Oct. 31, 2022
Partnership agreement
Series C preferred units, repurchased (in shares)	7,000	3,000	4,500	19,000
Total Consideration (in millions)	$ 6.5	$ 2.7	$ 3.9	$ 15.2
Percent Represented of Repurchased Preferred Units’ Par Value	93%	90%	87%	80%

Members' Equity - Board_s Autho

Members' Equity - Board’s Authorizations of the Ccommon Unit Repurchase Program (Details) - USD ($) $ in Millions	Dec. 31, 2023	Nov. 30, 2023	Dec. 31, 2022	Jul. 31, 2022	Jan. 31, 2022	Apr. 30, 2021	Nov. 30, 2020
Earnings Per Share [Abstract]
Stock repurchase program, authorized amount	$ 200		$ 200		$ 100	$ 100	$ 100
Stock repurchase program increase		$ 50		$ 100

Members' Equity - IP Repurchase

Members' Equity - IP Repurchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	20,377,407	18,374,054	6,091,001
Aggregate cost for common units	$ 234.8	$ 175	$ 40.1
Excise tax on common unit repurchases	$ 2	$ 0	$ 0
Public ENLC Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	11,530,962	11,630,351	6,091,001
Aggregate cost for common units	$ 134.5	$ 111.5	$ 40.1
ENCL Common Units Held by GIP
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	8,846,445	6,743,703
Aggregate cost for common units	$ 98.3	$ 63.5
Average price of shares repurchased (in dollars per share)	$ 11.11	$ 9.42
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Average price of shares repurchased (in dollars per share)	$ 11.67	$ 9.59	$ 6.59

Members' Equity - Narrative (De

Members' Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Feb. 19, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)		20,377,407	18,374,054	6,091,001
Common units repurchased		$ 234.8	$ 175	$ 40.1
Obligation to repurchase common units		$ 41.5
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units held (in shares)	3,280,637
Common units repurchased	$ 41.5
Price of shares purchased (in shares)	$ 12.66

Members' Equity - Summary (Deta

Members' Equity - Summary (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Distributed earnings allocated to:
Total distributed earnings													$ 238.2	$ 226.5	$ 197
Undistributed income (loss) allocated to:
Total undistributed loss, basic													(32)	134.8	(174.6)
Total undistributed loss, diluted													(32)	134.8	(174.6)
Net income attributable to ENLC allocated to:
Total net income (loss), basic													206.2	361.3	22.4
Total net income (loss), diluted													$ 206.2	$ 361.3	$ 22.4
Net income attributable to ENLC per unit:
Basic (in dollars per share)													$ 0.45	$ 0.76	$ 0.05
Diluted (in dollars per share)													$ 0.44	$ 0.74	$ 0.05
Weighted average basic common units outstanding (in units)													461.7	478.5	488.8
Dilutive effect of non-vested restricted units (in units)													4.3	6.8	5.5
Total weighted average diluted common units outstanding (in units)													466	485.3	494.3
Distribution declared/unit (in dollars per share)	$ 0.13250	$ 0.12500	$ 0.12500	$ 0.12500	$ 0.12500	$ 0.11250	$ 0.11250	$ 0.11250	$ 0.11250	$ 0.09375	$ 0.09375	$ 0.09375
Unvested unit-based awards
Distributed earnings allocated to:
Total distributed earnings													$ 3.9	$ 5.2	$ 4.5
Undistributed income (loss) allocated to:
Total undistributed loss, basic													(0.5)	3.1	(4)
Total undistributed loss, diluted													(0.5)	3.1	(4)
Net income attributable to ENLC allocated to:
Total net income (loss), basic													3.4	8.3	0.5
Total net income (loss), diluted													3.4	8.3	0.5
Common units
Distributed earnings allocated to:
Total distributed earnings													234.3	221.3	192.5
Undistributed income (loss) allocated to:
Total undistributed loss, basic													(31.5)	131.7	(170.6)
Total undistributed loss, diluted													(31.5)	131.7	(170.6)
Net income attributable to ENLC allocated to:
Total net income (loss), basic													202.8	353	21.9
Total net income (loss), diluted													$ 202.8	$ 353	$ 21.9

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates - Narrative (Details)	Dec. 31, 2023
GCF
Equity method investments
Ownership interest	38.75%
Cedar Cove JV
Equity method investments
Ownership interest	30%
Matterhorn JV
Equity method investments
Ownership interest	15%

Investment in Unconsolidated _4

Investment in Unconsolidated Affiliates - Summary of Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity method investments
Contributions	$ 68.1	$ 65.9	$ 0
Distributions	(2.5)	(0.7)	(3.9)
Equity in loss	(8.2)	(5.6)	(11.5)
Total investment in unconsolidated affiliates	150.5	90.2
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	143.2	85.8
GCF
Equity method investments
Contributions	24.6	1.5	0
Distributions	(2)	0	(3.5)
Equity in loss	(4.4)	(3.2)	(9.1)
GCF | EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	44.5	26.3
Cedar Cove JV
Equity method investments
Distributions	(0.5)	(0.7)	(0.4)
Equity in loss	(2.4)	(1.9)	(2.4)
Cedar Cove JV | EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	(7.3)	(4.4)
Matterhorn JV
Equity method investments
Contributions	43.5	64.4	0
Equity in loss	(1.4)	(0.5)	$ 0
Matterhorn JV | EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	$ 106	$ 63.9

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Allocation
Compensation expense	$ 19.2	$ 30.4	$ 25.3
Amount of related income tax benefit recognized in net income	4.5	7.1	5.9
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	3.7	5.7	6.6
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	$ 15.5	$ 24.7	$ 18.7

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended				12 Months Ended
	Mar. 31, 2023	Jun. 30, 2022	Mar. 31, 2022	Jan. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restricted incentive units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Vesting period					3 years
Unrecognized compensation cost related to non-vested restricted incentive units					$ 16.7
Unrecognized compensation costs, weighted average period for recognition					1 year 9 months 18 days
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)					2,979,154
Granted (in shares)					420,128
Vested (in shares)					(1,091,523)
Forfeited (in shares)					(71,015)
Non-vested, end of period (in shares)					2,236,744	2,979,154
Aggregate intrinsic value, end of period (in millions)					$ 27.2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)					$ 6.44
Granted (in dollars per share)					11.67
Vested (in dollars per share)					8.30
Forfeited (in dollars per share)					10.97
Non-vested, end of period (in dollars per share)					$ 6.37	$ 6.44
Vesting period					3 years
Aggregate intrinsic value of units vested					$ 26.1	$ 20.4	$ 0.6
Fair value of units vested					9.1	$ 26.2	4.4
Unrecognized compensation cost related to non-vested restricted incentive units					$ 8.7
Unrecognized compensation costs, weighted average period for recognition					1 year 4 months 24 days
Performance Shares With Vesting Conditions
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)			$ 8.90
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in shares)			88,863
ENLC | Restricted incentive units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)					6,775,186
Granted (in shares)					1,587,965
Vested (in shares)					(2,489,603)
Forfeited (in shares)					(427,568)
Non-vested, end of period (in shares)					5,445,980	6,775,186
Aggregate intrinsic value, end of period (in millions)					$ 66.2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)					$ 5.89
Granted (in dollars per share)					11.03
Vested (in dollars per share)					5.96
Forfeited (in dollars per share)					6.98
Non-vested, end of period (in dollars per share)					$ 7.27	$ 5.89
Units withheld for payroll taxes (in shares)					756,556
Aggregate intrinsic value of units vested					$ 30.5	$ 24.4	5.6
Fair value of units vested					$ 14.8	$ 19	$ 16.3
ENLC | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)	$ 11.67	$ 11.71	$ 11.90	$ 4.70
Beginning TSR price (in dollars per share)	$ 10.40	$ 8.54	$ 8.83	$ 3.71
Risk-free interest rate	3.76%	3.35%	2.15%	0.17%
Volatility factor	64%	76%	75%	71%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units withheld for payroll taxes (in shares)					811,114
ENLC | Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting					0%
ENLC | Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting					200%

Employee Incentive Plans - Summ

Employee Incentive Plans - Summary of Tranche Vesting Levels (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Below Threshold | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the tranche TSR and CF units	0%
Maximum performance level	25%
Below Threshold | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC's Archived DCF / FCFAD	$ 801	$ 154	$ 205
Vesting percentage of the tranche TSR and CF units		0%
Threshold | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the tranche TSR and CF units	50%
Maximum performance level	25%
Threshold | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC's Archived DCF / FCFAD	$ 801	$ 154	205
Vesting percentage of the tranche TSR and CF units		50%
Target | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the tranche TSR and CF units	100%
Maximum performance level	50%
Target | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC's Archived DCF / FCFAD	$ 932	$ 202	256
Vesting percentage of the tranche TSR and CF units		100%
Maximum | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the tranche TSR and CF units	200%
Maximum performance level	85%	75%
Maximum | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC's Archived DCF / FCFAD	$ 1,123	$ 241	$ 300
Vesting percentage of the tranche TSR and CF units		200%

Employee Incentive Plans - Bene

Employee Incentive Plans - Benefit Plan (Details) - EnLink Midstream Partners, LP - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	100%
Employer matching contribution, percent of employees' gross pay	6%
Employer benefit plan contributions	$ 8.4	$ 7.4	$ 7

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) - USD ($)	Dec. 31, 2023	Jan. 31, 2023	Dec. 31, 2021	Dec. 10, 2021	Apr. 30, 2019
Derivatives
Derivative, notional amount		$ 400,000,000			$ 850,000,000
Derivative, fixed interest rate		3.8565%
Cash flow hedge gain (loss) amortized into interest rate expense in the next 12 months	$ 3,300,000
2021 Year
Derivatives
Interest Rate Swaps Terminations			$ 200,000,000
Cash Payments Associated with Interest Rate Swaps Terminations			$ 1,800,000
December 2021
Derivatives
Interest Rate Swaps Terminations				$ 150,000,000
Commodity Swaps
Derivatives
Maximum loss if counterparties fail to perform	100,600,000
Maximum potential exposure to credit losses net exposure	$ 15,200,000

Derivatives - Components Of The

Derivatives - Components Of The Unrealized Gain On Designated Cash Flow Hedge (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Derivatives
Change in fair value of derivatives		$ (12.1)		$ 40.2		$ (12.4)
Tax expense		(0.2)		(0.5)		(4.3)
Unrealized gain on designated cash flow hedge	[1]	0.7	[2]	1.4	[3]	13.9	[4]
Interest rate swaps
Derivatives
Change in fair value of derivatives		$ 0.9		$ 1.9		$ 18.2
[1] Includes tax expense of $0.2 million, $0.5 million, and $4.3 million for the years ended December 31, 2023, 2022, and 2021, respectively. Includes tax expense of $0.2 million. Includes tax expense of $0.5 million. Includes tax expense of $4.3 million.

Derivatives - Fair Value of Der

Derivatives - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivatives
Fair value of derivative assets—current	$ 76.9	$ 68.4
Fair value of derivative liabilities—long-term	(26.7)	(2.7)
Interest rate swaps
Derivatives
Fair value of derivative assets—current	3.3	0
Fair value of derivative liabilities—long-term	(2.4)	0
Net fair value of commodity derivatives	$ 0.9	$ 0

Derivatives - Interest Rate (De

Derivatives - Interest Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense (income)	$ (4.5)	$ 1.9	$ 18.3

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivatives
Change in fair value of derivatives	$ (12.1)	$ 40.2	$ (12.4)
Gain (loss) on derivative activity	20.7	14.3	(159.1)
EnLink Midstream Partners, LP | Commodity Swaps
Derivatives
Change in fair value of derivatives	(12.1)	40.2	(12.4)
Realized gain (loss) on derivatives	32.8	(25.9)	(146.7)
Gain (loss) on derivative activity	$ 20.7	$ 14.3	$ (159.1)

Derivatives - Fair Value of Ass

Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivatives
Fair value of derivative assets—current	$ 76.9	$ 68.4
Fair value of derivative assets—long-term	27	2.9
Fair value of derivative liabilities—current	(62.7)	(42.9)
Fair value of derivative liabilities—long-term	(26.7)	(2.7)
Commodity Swaps
Derivatives
Net fair value of commodity derivatives	13.6
EnLink Midstream Partners, LP | Commodity Swaps
Derivatives
Fair value of derivative assets—current	73.6	68.4
Fair value of derivative assets—long-term	27	2.9
Fair value of derivative liabilities—current	(62.7)	(42.9)
Fair value of derivative liabilities—long-term	(24.3)	(2.7)
Net fair value of commodity derivatives	$ 13.6	$ 25.7

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) - Commodity Swaps gal in Millions, bbl in Millions, BTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) BTU gal bbl	Dec. 31, 2022 USD ($)
Derivatives
Net Fair Value	$ 13.6
EnLink Midstream Partners, LP
Derivatives
Net Fair Value	$ 13.6	$ 25.7
EnLink Midstream Partners, LP | NGL | Short
Derivatives
Notional amount (in gallons or MMbbls) | gal	111.8
Net Fair Value	$ (0.8)
EnLink Midstream Partners, LP | NGL | Long
Derivatives
Notional amount (in gallons or MMbbls) | gal	58
Net Fair Value	$ 1.1
EnLink Midstream Partners, LP | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | BTU	145.8
Net Fair Value	$ 86.6
EnLink Midstream Partners, LP | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | BTU	122.4
Net Fair Value	$ (75.5)
EnLink Midstream Partners, LP | Condensate | Short
Derivatives
Notional amount (in gallons or MMbbls) | bbl	7.4
Net Fair Value	$ 2.3
EnLink Midstream Partners, LP | Crude and condensate | Long
Derivatives
Notional amount (in gallons or MMbbls) | bbl	0.1
Net Fair Value	$ (0.1)

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Interest rate swaps
Fair Value
Net Fair Value	$ 0.9	$ 0
Commodity Swaps
Fair Value
Net Fair Value	13.6
Level 2 | Interest rate swaps | Recurring
Fair Value
Net Fair Value	0.9	0
Level 2 | Commodity Swaps | Recurring
Fair Value
Net Fair Value	$ 13.6	$ 25.7

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Apr. 30, 2022	Dec. 31, 2021	Apr. 30, 2021	Dec. 31, 2020
Fair Value
Contingent consideration	$ 6,700,000	$ 5,500,000		$ 6,900,000		$ 0
Debt issuance costs	32,100,000	34,900,000
Amarillo Rattler, LLC
Fair Value
Contingent consideration	4,800,000	4,200,000		$ 6,900,000		$ 0
Business combination, maximum earnout			$ 15,000,000		$ 15,000,000
Carrying Value
Fair Value
Long-term debt	4,568,900,000	4,723,500,000
Contingent consideration	6,700,000	5,500,000
Fair Value
Fair Value
Long-term debt	4,427,000,000	4,385,900,000
Contingent consideration	$ 6,700,000	$ 5,500,000

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) claim defendant
Koch | EnLink Gas Marketing, LP
Commitments and Contingencies
Loss contingency, damages sought, value | $	$ 53.9
Harris County Multi-District Litigation | EnLink Energy GP, LLC
Commitments and Contingencies
Number of defendants | defendant	350
Number of filed cases	150
Number of third parties involved in economic damage claims	90

Segment Information - Narrative

Segment Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting [Abstract]
Number of reportable segments	5

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 6,879.4	$ 9,527.8	$ 6,845
Realized gain (loss) on derivatives	32.8	(25.9)	(146.7)
Change in fair value of derivatives	(12.1)	40.2	(12.4)
Total revenues	6,900.1	9,542.1	6,685.9
Cost of sales, exclusive of operating expenses and depreciation and amortization	(4,856.1)	(7,572.8)	(5,189.9)
Adjusted gross margin	2,044	1,969.3	1,496
Operating expenses	(558.2)	(524.9)	(362.9)
Segment profit	1,485.8	1,444.4	1,133.1
Depreciation and amortization	(657.1)	(639.4)	(607.5)
Gross margin	828.7	805	525.6
Impairments	(20.7)	0	(0.8)
Gain (loss) on disposition of assets	0.3	(18)	1.5
General and administrative	(115.5)	(125.2)	(107.8)
Interest expense, net of interest income	(271.7)	(245)	(238.7)
Loss on extinguishment of debt	0	(6.2)	0
Loss from unconsolidated affiliate investments	(8.2)	(5.6)	(11.5)
Other income (loss)	(0.1)	0.8	0
Income before non-controlling interest and income taxes	412.8	405.8	168.3
Capital expenditures	486.8	337.6	196
Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	2,825.2	3,865.4	2,390.6
Realized gain (loss) on derivatives	3	(9)	(75.6)
Change in fair value of derivatives	(5)	9.6	(7.7)
Total revenues	2,823.2	3,866	2,307.3
Cost of sales, exclusive of operating expenses and depreciation and amortization	(2,205.5)	(3,280.3)	(1,996.1)
Adjusted gross margin	617.7	585.7	311.2
Operating expenses	(221.3)	(200.2)	(81.5)
Segment profit	396.4	385.5	229.7
Depreciation and amortization	(166.6)	(154.5)	(139.9)
Gross margin	229.8	231	89.8
Impairments	0		0
Gain (loss) on disposition of assets	0.2	0.1	0
General and administrative	0	0	0
Interest expense, net of interest income	0	0	0
Loss on extinguishment of debt		0
Loss from unconsolidated affiliate investments	0	0	0
Other income (loss)	0	0
Income before non-controlling interest and income taxes	230	231.1	89.8
Capital expenditures	267.3	210.2	141.6
Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3,903.6	5,966.8	4,581.4
Realized gain (loss) on derivatives	2.6	2.9	(42.3)
Change in fair value of derivatives	4.1	7.7	0.7
Total revenues	3,910.3	5,977.4	4,539.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	(3,388.4)	(5,462.4)	(4,091.2)
Adjusted gross margin	521.9	515	448.6
Operating expenses	(130.3)	(140.7)	(123.7)
Segment profit	391.6	374.3	324.9
Depreciation and amortization	(151.3)	(156.5)	(141)
Gross margin	240.3	217.8	183.9
Impairments	(20.7)		(0.6)
Gain (loss) on disposition of assets	(2)	(13.8)	1.2
General and administrative	0	0	0
Interest expense, net of interest income	0	0	0
Loss on extinguishment of debt		0
Loss from unconsolidated affiliate investments	0	0	0
Other income (loss)	0	0
Income before non-controlling interest and income taxes	217.6	204	184.5
Capital expenditures	68.6	33.7	9.3
Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,167.1	1,610.5	1,226.8
Realized gain (loss) on derivatives	6.5	(13.1)	(22.6)
Change in fair value of derivatives	(2.2)	5.6	0
Total revenues	1,171.4	1,603	1,204.2
Cost of sales, exclusive of operating expenses and depreciation and amortization	(645.6)	(1,124.4)	(796.6)
Adjusted gross margin	525.8	478.6	407.6
Operating expenses	(103.8)	(90.9)	(80)
Segment profit	422	387.7	327.6
Depreciation and amortization	(217.7)	(201.8)	(204.3)
Gross margin	204.3	185.9	123.3
Impairments	0		0
Gain (loss) on disposition of assets	0.9	0.5	0
General and administrative	0	0	0
Interest expense, net of interest income	0	0	0
Loss on extinguishment of debt		0
Loss from unconsolidated affiliate investments	0	0	0
Other income (loss)	0	0
Income before non-controlling interest and income taxes	205.2	186.4	123.3
Capital expenditures	69.2	63.8	30.4
North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	709.5	1,011.1	872
Realized gain (loss) on derivatives	20.7	(6.7)	(6.2)
Change in fair value of derivatives	(9)	17.3	(5.4)
Total revenues	721.2	1,021.7	860.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(342.6)	(631.7)	(531.8)
Adjusted gross margin	378.6	390	328.6
Operating expenses	(102.8)	(93.1)	(77.7)
Segment profit	275.8	296.9	250.9
Depreciation and amortization	(115.8)	(121.1)	(114.3)
Gross margin	160	175.8	136.6
Impairments	0		0
Gain (loss) on disposition of assets	1.2	(4.8)	0.3
General and administrative	0	0	0
Interest expense, net of interest income	0	0	0
Loss on extinguishment of debt		0
Loss from unconsolidated affiliate investments	0	0	0
Other income (loss)	0	0
Income before non-controlling interest and income taxes	161.2	171	136.9
Capital expenditures	75.5	22.8	11.9
Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(1,726)	(2,926)	(2,225.8)
Realized gain (loss) on derivatives	0	0	0
Change in fair value of derivatives	0	0	0
Total revenues	(1,726)	(2,926)	(2,225.8)
Cost of sales, exclusive of operating expenses and depreciation and amortization	1,726	2,926	2,225.8
Adjusted gross margin	0	0	0
Operating expenses	0	0	0
Segment profit	0	0	0
Depreciation and amortization	(5.7)	(5.5)	(8)
Gross margin	(5.7)	(5.5)	(8)
Impairments	0		(0.2)
Gain (loss) on disposition of assets	0	0	0
General and administrative	(115.5)	(125.2)	(107.8)
Interest expense, net of interest income	(271.7)	(245)	(238.7)
Loss on extinguishment of debt		(6.2)
Loss from unconsolidated affiliate investments	(8.2)	(5.6)	(11.5)
Other income (loss)	(0.1)	0.8
Income before non-controlling interest and income taxes	(401.2)	(386.7)	(366.2)
Capital expenditures	6.2	7.1	2.8
Product sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers	5,755.6	8,564.9	5,994
Product sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,691.4	2,235.8	1,287.7
Product sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3,691.5	5,675	4,258.6
Product sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	302.3	513.7	296.6
Product sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	70.4	140.4	151.1
Product sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Natural gas sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,159.2	2,713.6	1,666.3
Natural gas sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	453.4	1,078.7	609.4
Natural gas sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	444.7	1,128.4	693.5
Natural gas sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	184.5	367.5	213.4
Natural gas sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	76.6	139	150
Natural gas sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
NGL sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3,021.5	4,207.3	3,357.1
NGL sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(12)	(1.5)	0.9
NGL sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3,031.2	4,196.6	3,353.1
NGL sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	8.5	10.8	2
NGL sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(6.2)	1.4	1.1
NGL sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Crude oil and condensate sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,574.9	1,644	970.6
Crude oil and condensate sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,250	1,158.6	677.4
Crude oil and condensate sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	215.6	350	212
Crude oil and condensate sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	109.3	135.4	81.2
Crude oil and condensate sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Crude oil and condensate sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Product sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Product sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	927.9	1,495.6	1,008.4
Product sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	22.4	97.7	129.7
Product sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	465.6	774.9	630.9
Product sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	306.4	555.9	454.1
Product sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(1,722.3)	(2,924.1)	(2,223.1)
NGL sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
NGL sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	927.9	1,495.6	1,008.4
NGL sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	22.4	97.7	129.7
NGL sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	465.6	774.6	630.8
NGL sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	295.9	543.6	447
NGL sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(1,711.8)	(2,911.5)	(2,215.9)
Crude oil and condensate sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Crude oil and condensate sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Crude oil and condensate sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Crude oil and condensate sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0.3	0.1
Crude oil and condensate sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	10.5	12.3	7.1
Crude oil and condensate sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(10.5)	(12.6)	(7.2)
Midstream services
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,123.8	962.9	851
Midstream services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	205.9	134	94.5
Midstream services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	189.7	193.9	190.7
Midstream services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	399.2	321.8	299
Midstream services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	329	313.2	266.8
Midstream services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Gathering and transportation
Segment Reporting Information [Line Items]
Revenue from contracts with customers	635.2	521.3	455.4
Gathering and transportation | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	114.6	72.6	46.8
Gathering and transportation | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	79.9	75.5	64.7
Gathering and transportation | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	236.8	187.5	186.9
Gathering and transportation | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	203.9	185.7	157
Gathering and transportation | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Processing
Segment Reporting Information [Line Items]
Revenue from contracts with customers	329.5	286.3	238.5
Processing | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	60.1	39.2	29.1
Processing | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1.6	1.5	2.4
Processing | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	144.4	119.7	98.7
Processing | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	123.4	125.9	108.3
Processing | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
NGL services
Segment Reporting Information [Line Items]
Revenue from contracts with customers	87.5	82.2	82.9
NGL services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
NGL services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	87.3	82	82.6
NGL services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
NGL services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0.2	0.2	0.3
NGL services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Crude services
Segment Reporting Information [Line Items]
Revenue from contracts with customers	61.7	70.3	71.2
Crude services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	23.9	21.4	18.4
Crude services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	19.6	33.3	39.3
Crude services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	17.5	14.9	12.8
Crude services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0.7	0.7	0.7
Crude services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Other services
Segment Reporting Information [Line Items]
Revenue from contracts with customers	9.9	2.8	3
Other services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	7.3	0.8	0.2
Other services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1.3	1.6	1.7
Other services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0.5	(0.3)	0.6
Other services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0.8	0.7	0.5
Other services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Midstream services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Midstream services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Midstream services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0.2	2.4
Midstream services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0.1	0.3
Midstream services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3.7	1.6	0
Midstream services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(3.7)	(1.9)	(2.7)
NGL services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
NGL services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
NGL services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
NGL services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
NGL services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	3.7	1.6
NGL services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ (3.7)	(1.6)
Crude services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0	0
Crude services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0	0
Crude services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0	0
Crude services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.1	0.3
Crude services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0	0
Crude services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(0.1)	(0.3)
Other services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0	0
Other services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(0.2)
Other services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers			0
Other services—related parties | Permian | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0
Other services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers			2.4
Other services—related parties | Louisiana | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.2
Other services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers			0
Other services—related parties | Oklahoma | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0
Other services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers			0
Other services—related parties | North Texas | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers		$ 0
Other services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers			$ (2.4)

Segment Information - Amortizat

Segment Information - Amortization Expense (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Assets	$ 8,328.6	$ 8,651
Permian
Segment Reporting Information [Line Items]
Assets	2,813.6	2,661.4
Louisiana
Segment Reporting Information [Line Items]
Assets	2,031.8	2,310.7
Oklahoma
Segment Reporting Information [Line Items]
Assets	2,275.8	2,420.4
North Texas
Segment Reporting Information [Line Items]
Assets	1,017.7	1,094.6
Corporate
Segment Reporting Information [Line Items]
Assets	$ 189.7	$ 163.9

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental disclosures of cash flow information:
Cash paid for interest	$ 266.9	$ 221.1	$ 208.8
Cash paid for income taxes	1.6	0.7	0.3
Cash paid for operating leases included in cash flows from operating activities	35.1	30.5	24.6
Non-cash investing activities:
Non-cash accrual of property and equipment	41.1	4.2	12
Non-cash right-of-use assets obtained in exchange for operating lease liabilities	36.5	33.4	18.7
Non-cash acquisitions	0	1.3	16.9
Non-cash financing activities:
Redemption of mandatorily redeemable non-controlling interest	$ 0	$ (6.5)	$ 0

Other Information - Other Curre

Other Information - Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Other current assets:
Product inventory	$ 46.4	$ 147.1
Prepaid expenses and other	19	19.5
Other current assets	$ 65.4	$ 166.6

Other Information - Other Cur_2

Other Information - Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Other current liabilities:
Accrued interest	$ 63.4	$ 57.6
Accrued wages and benefits, including taxes	23.2	38.1
Accrued ad valorem taxes	33.3	32
Accrued settlement of mandatorily redeemable non-controlling interest	0	10.5
Capital expenditure accruals	64.6	23.4
Short-term lease liability	28.2	26.2
Operating expense accruals	21.5	18.5
Other	44.3	23.3
Other current liabilities	$ 278.5	$ 229.6

Uncategorized Items - enlc-2023

Label	Element	Value
Redeemable Noncontrolling Interest, Fair Value Adjustment	enlc_RedeemableNoncontrollingInterestFairValueAdjustment	$ 800,000
Common Units [Member]
Redeemable Noncontrolling Interest, Fair Value Adjustment	enlc_RedeemableNoncontrollingInterestFairValueAdjustment	$ 800,000
[1] Relates to book-to-tax differences recorded upon the settlement of the mandatorily redeemable non-controlling interest.