EnLink Midstream (ENLC) 10-Q 4 Aug 22 2022 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2022	Jul. 28, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
Document Transition Report	false
Entity File Number	001-36336
Entity Registrant Name	ENLINK MIDSTREAM, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-4108528
Entity Address, Address Line One	1722 Routh St., Suite 1300
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75201
City Area Code	214
Local Phone Number	953-9500
Title of 12(b) Security	Common Units Representing Limited Liability Company Interests
Trading Symbol	ENLC
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		478,933,388
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2022
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Jun. 30, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents		$ 18.1	$ 26.2
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively		101.1	94.9
Accrued revenue and other		913.7	693.3
Fair value of derivative assets		95.6	22.4
Other current assets		159.7	83.6
Total current assets		1,288.2	920.4
Property and equipment, net of accumulated depreciation of $4,570.4 and $4,332.0, respectively		6,259	6,388.3
Intangible assets, net of accumulated amortization of $859.8 and $795.1, respectively		985	1,049.7
Investment in unconsolidated affiliates		53	28
Fair value of derivative assets		0	0.2
Other assets, net		93.6	96.6
Total assets		8,678.8	8,483.2
Current liabilities:
Accounts payable and drafts payable		177.9	139.6
Accrued gas, NGLs, condensate, and crude oil purchases	[1]	768.9	521.5
Fair value of derivative liabilities		88.7	34.9
Other current liabilities		184.1	202.9
Total current liabilities		1,219.6	898.9
Long-term debt, net of unamortized issuance cost		4,320	4,363.7
Other long-term liabilities		93.3	93.9
Deferred tax liability, net		138.7	137.5
Fair value of derivative liabilities		1.2	2.2
Members’ equity:
Members’ equity (479,825,804 and 484,277,258 units issued and outstanding, respectively)		1,293.3	1,325.8
Accumulated other comprehensive loss		(1.3)	(1.4)
Non-controlling interest		1,614	1,662.6
Total members’ equity		2,906	2,987
Commitments and contingencies (Note 15)
Total liabilities and members’ equity		$ 8,678.8	$ 8,483.2
[1]Includes related party accounts payable balances of $5.7 million and $1.6 million at June 30, 2022 and December 31, 2021, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
ASSETS
Allowance for bad debt	$ 0.3	$ 0.3
Property and equipment, accumulated depreciation	4,570.4	4,332
Intangible assets, accumulated amortization	$ 859.8	$ 795.1
Members’ equity:
Common units issued (in shares)	479,825,804	484,277,258
Common units outstanding (in shares)	484,277,258	479,825,804
Accounts payable to related party	$ 5.7	$ 1.6

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Revenues:
Revenue from contracts with customers		$ 2,596.1	$ 1,444.9	$ 4,855	$ 2,776.7
Gain (loss) on derivative activity		4.5	(38.2)	(26.7)	(121.6)
Total revenues		2,600.6	1,406.7	4,828.3	2,655.1
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	2,105.1	1,055.1	3,899.6	1,989.8
Operating expenses		128.9	96.8	249.8	153.1
Depreciation and amortization		159	151.9	311.9	302.9
(Gain) loss on disposition of assets		(0.4)	(0.3)	4.7	(0.3)
General and administrative		28.4	26.1	57.4	52.1
Total operating costs and expenses		2,421	1,329.6	4,523.4	2,497.6
Operating income		179.6	77.1	304.9	157.5
Other income (expense):
Interest expense, net of interest income		(55.5)	(60)	(110.6)	(120)
Loss on extinguishment of debt		(0.5)	0	(0.5)	0
Loss from unconsolidated affiliate investments		(1.2)	(1.3)	(2.3)	(7.6)
Other income		0.2	0.2	0.3	0.1
Total other expense		(57)	(61.1)	(113.1)	(127.5)
Income before non-controlling interest and income taxes		122.6	16	191.8	30
Income tax benefit (expense)		1.3	(6.6)	(1.9)	(8)
Net income		123.9	9.4	189.9	22
Net income attributable to non-controlling interest		38.6	31	69.4	56.3
Net income (loss) attributable to ENLC		$ 85.3	$ (21.6)	$ 120.5	$ (34.3)
Net income (loss) attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ 0.18	$ (0.04)	$ 0.25	$ (0.07)
Diluted common unit (in dollars per share)		$ 0.17	$ (0.04)	$ 0.25	$ (0.07)
Product sales
Revenues:
Revenue from contracts with customers		$ 2,370.5	$ 1,235.6	$ 4,414.4	$ 2,358.5
Midstream services
Revenues:
Revenue from contracts with customers		$ 225.6	$ 209.3	$ 440.6	$ 418.2
[1] Includes related party cost of sales of $9.1 million and $3.6 million for the three months ended June 30, 2022 and 2021, respectively, and $19.7 million and $6.8 million for the six months ended June 30, 2022 and 2021, respectively.

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Statement [Abstract]
Related party cost of sales	$ 9.1	$ 3.6	$ 19.7	$ 6.8

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021		Jun. 30, 2022	Jun. 30, 2021
Statement of Comprehensive Income [Abstract]
Net income		$ 123.9	$ 9.4		$ 189.9	$ 22
Unrealized gain on designated cash flow hedge	[1]	0	3.7	[2]	0.1	7.3
Comprehensive income		123.9	13.1		190	29.3
Comprehensive income attributable to non-controlling interest		38.6	31		69.4	56.3
Comprehensive income (loss) attributable to ENLC		$ 85.3	$ (17.9)		$ 120.6	$ (27)
[1]Includes tax expense of $1.1 million and $2.2 million for the three and six months ended June 30, 2021, respectively.[2]Includes tax expense of $1.1 million.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2021
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ 1.1	$ 1.1	$ 2.2

Consolidated Statement of Chang

Consolidated Statement of Changes in Members' Equity - USD ($) $ in Millions		Total		Common Units	Accumulated Other Comprehensive Loss	Non-Controlling Interest	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 restricted units for common units, net of units withheld for taxes		(1.2)		$ (1.2)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				700,000
Unit-based compensation		6.5		$ 6.5
Contributions from non-controlling interests		0.9				0.9
Distributions		(72.9)		(47.1)		(25.8)	$ (0.2)
Unrealized gain on designated cash flow hedge	[1]	3.6			3.6
Fair value adjustment related to redeemable non-controlling interest		(0.1)		(0.1)			0.2
Net income (loss)		12.6		(12.7)		25.3
Member equity, end balance at Mar. 31, 2021		3,162.4		$ 1,454.2	(11.7)	1,719.9
Units outstanding, end balance (in shares) at Mar. 31, 2021				490,100,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2020							0
Temporary Equity [Abstract]
Distributions		(72.9)		$ (47.1)		(25.8)	(0.2)
Fair value adjustment related to redeemable non-controlling interest		(0.1)		(0.1)			0.2
Redeemable noncontrolling interest, ending balance at Mar. 31, 2021							0
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
Unrealized gain on designated cash flow hedge	[2]	7.3
Common units repurchased		$ (2)
Common units repurchased (in shares)		(317,751)
Member equity, end balance at Jun. 30, 2021		$ 3,098		$ 1,390.1	(8)	1,715.9
Units outstanding, end balance (in shares) at Jun. 30, 2021				489,900,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2020							0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2021							0
Member equity, beginning balance at Mar. 31, 2021		3,162.4		$ 1,454.2	(11.7)	1,719.9
Units outstanding, beginning balance (in shares) at Mar. 31, 2021				490,100,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.2)		$ (0.2)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				100,000
Unit-based compensation		6.4		$ 6.4
Contributions from non-controlling interests		1				1
Distributions		(82.7)		(46.7)		(36)
Unrealized gain on designated cash flow hedge	[3]	3.7	[2]		3.7
Common units repurchased		$ (2)		$ (2)
Common units repurchased (in shares)		(317,751)		(300,000)
Net income (loss)		$ 9.4		$ (21.6)		31	0
Member equity, end balance at Jun. 30, 2021		3,098		$ 1,390.1	(8)	1,715.9
Units outstanding, end balance (in shares) at Jun. 30, 2021				489,900,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2021							0
Temporary Equity [Abstract]
Distributions		(82.7)		$ (46.7)		(36)
Redeemable noncontrolling interest, ending balance at Jun. 30, 2021							$ 0
Member equity, beginning balance at Dec. 31, 2021		$ 2,987		$ 1,325.8	(1.4)	1,662.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2021		484,277,258		484,300,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		$ (4.2)		$ (4.2)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				1,200,000
Unit-based compensation		8.1		$ 8.1
Contributions from non-controlling interests		7.3				7.3
Distributions		(91)		(56.4)		(34.6)
Unrealized gain on designated cash flow hedge		0.1			0.1
Redemption of non-controlling interest		(50.5)				(50.5)
Common units repurchased		(17)		$ (17)
Common units repurchased (in shares)				(2,100,000)
Net income (loss)		66		$ 35.2		30.8
Member equity, end balance at Mar. 31, 2022		2,905.8		$ 1,291.5	(1.3)	1,615.6
Units outstanding, end balance (in shares) at Mar. 31, 2022				483,400,000
Temporary Equity [Abstract]
Distributions		(91)		$ (56.4)		(34.6)
Member equity, beginning balance at Dec. 31, 2021		$ 2,987		$ 1,325.8	(1.4)	1,662.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2021		484,277,258		484,300,000
Increase (Decrease) in Members' Equity
Unrealized gain on designated cash flow hedge	[2]	$ 0.1
Common units repurchased		$ (50.7)
Common units repurchased (in shares)		(5,690,307)
Member equity, end balance at Jun. 30, 2022		$ 2,906		$ 1,293.3	(1.3)	1,614
Units outstanding, end balance (in shares) at Jun. 30, 2022		479,825,804		479,800,000
Member equity, beginning balance at Mar. 31, 2022		$ 2,905.8		$ 1,291.5	(1.3)	1,615.6
Units outstanding, beginning balance (in shares) at Mar. 31, 2022				483,400,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.2)		$ (0.2)
Unit-based compensation		5.7		5.7
Contributions from non-controlling interests		2				2
Distributions		(97.5)		(55.3)		(42.2)
Unrealized gain on designated cash flow hedge	[2]	0
Common units repurchased		$ (33.7)		$ (33.7)
Common units repurchased (in shares)		(3,596,465)		(3,600,000)
Net income (loss)		$ 123.9		$ 85.3		38.6
Member equity, end balance at Jun. 30, 2022		$ 2,906		$ 1,293.3	$ (1.3)	1,614
Units outstanding, end balance (in shares) at Jun. 30, 2022		479,825,804		479,800,000
Temporary Equity [Abstract]
Distributions		$ (97.5)		$ (55.3)		$ (42.2)
[1]Includes tax expense of $1.1 million.[2]Includes tax expense of $1.1 million and $2.2 million for the three and six months ended June 30, 2021, respectively.[3]Includes tax expense of $1.1 million.

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2021
Statement of Stockholders' Equity [Abstract]
Tax expense	$ 1.1	$ 1.1	$ 2.2

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Cash flows from operating activities:
Net income	$ 189.9	$ 22
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	311.9	302.9
Utility credits redeemed (earned)	11.6	(43.8)
Deferred income tax expense	1.2	7.9
(Gain) Loss on disposition of assets	4.7	(0.3)
Non-cash unit-based compensation	12.3	12.9
Amortization of designated cash flow hedge	0.1	6
Payments to terminate interest rate swaps	0	(1.3)
Non-cash (gain) loss on derivatives recognized in net income	(18.6)	34.2
Loss on extinguishment of debt	0.5	0
Amortization of debt issuance costs and net discount of senior unsecured notes	2.6	2.5
Loss from unconsolidated affiliate investments	2.3	7.6
Other operating activities	(2)	(2.5)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(226.7)	(61.4)
Natural gas and NGLs inventory, prepaid expenses, and other	(83.2)	(47.8)
Accounts payable, accrued product purchases, and other accrued liabilities	276	163.3
Net cash provided by operating activities	482.6	402.2
Cash flows from investing activities:
Additions to property and equipment	(124.1)	(62.5)
Contributions to unconsolidated affiliate investments	(26.6)	0
Acquisitions, net of cash acquired	0	(55)
Distribution from unconsolidated affiliate investments in excess of earnings	0.4	3.7
Other investing activities	1	1.6
Net cash used in investing activities	(149.3)	(112.2)
Cash flows from financing activities:
Proceeds from borrowings	1,135	539.5
Repayments on borrowings	(1,177)	(679.5)
Distributions to members	(111.7)	(93.8)
Distributions to non-controlling interests	(76.8)	(62)
Payment of installment payable for the Amarillo Rattler Acquisition	(10)	0
Redemption of Series B Preferred Units	(50.5)	0
Contributions from non-controlling interests	9.3	1.9
Common unit repurchases	(50.7)	(2)
Other financing activities	(9)	(0.9)
Net cash used in financing activities	(341.4)	(296.8)
Net decrease in cash and cash equivalents	(8.1)	(6.8)
Cash and cash equivalents, beginning of period	26.2	39.6
Cash and cash equivalents, end of period	18.1	32.8
Supplemental disclosures of cash flow information:
Cash paid for interest	107.8	97.1
Cash paid for income taxes	0.8	0.2
Non-cash investing activities:
Non-cash accrual of property and equipment	(1.6)	6.9
Non-cash acquisitions	0	16.5
Right-of-use assets obtained in exchange for operating lease liabilities	$ 15.3	$ 10.7

General

General	6 Months Ended
	Jun. 30, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	(1) General In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership. Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information. a. Organization of Business ENLC is a Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.” ENLC owns all of ENLK’s common units and also owns all of the membership interests of the General Partner. The General Partner manages ENLK’s operations and activities. b. Nature of Business We primarily focus on providing midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. As of June 30, 2022, our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers. Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets.

Significant Accounting Policies

Significant Accounting Policies	6 Months Ended
	Jun. 30, 2022
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies a. Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation. b. Revenue Recognition The following table summarizes the contractually committed fees (in millions) that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods. Contractually Committed Fees Commitments 2022 (remaining) $ 69.6 2023 119.7 2024 99.9 2025 67.0 2026 59.9 Thereafter 290.9 Total $ 707.0

Intangible Assets

Intangible Assets	6 Months Ended
	Jun. 30, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	(3) Intangible Assets Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years. The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Six Months Ended June 30, 2022 Customer relationships, beginning of period $ 1,844.8 $ (795.1) $ 1,049.7 Amortization expense — (64.7) (64.7) Customer relationships, end of period $ 1,844.8 $ (859.8) $ 985.0 Amortization expense was $31.9 million and $31.6 million for the three months ended June 30, 2022 and 2021, respectively, and $64.7 million and $62.5 million for the six months ended June 30, 2022 and 2021, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2022 (remaining) $ 63.7 2023 127.6 2024 127.6 2025 110.2 2026 106.3 Thereafter 449.6 Total $ 985.0

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2022
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions (a) Transactions with Cedar Cove JV For the three and six months ended June 30, 2022, we recorded cost of sales of $9.1 million and $19.7 million, respectively, and for the three and six months ended June 30, 2021, we recorded cost of sales of $3.6 million and $6.8 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $5.7 million and $1.6 million at June 30, 2022 and December 31, 2021, respectively. (b) Transactions with GIP General and Administrative Expenses. For the three and six months ended June 30, 2021, we recorded general and administrative expenses of $0.1 million and $0.2 million, respectively, related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three and six months ended June 30, 2022. GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, 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. See “Note 8—Members’ Equity” for additional information on the activity relating to the GIP repurchase agreement.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2022
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of June 30, 2022 and December 31, 2021, long-term debt consisted of the following (in millions): June 30, 2022 December 31, 2021 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ — $ — $ — $ 15.0 $ — $ 15.0 AR Facility due 2025 (2) 325.0 — 325.0 350.0 — 350.0 ENLK’s 4.40% Senior unsecured notes due 2024 519.8 0.5 520.3 521.8 0.7 522.5 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.3) 720.5 720.8 (0.4) 720.4 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.3) 490.7 491.0 (0.3) 490.7 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 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 (5.3) 444.7 450.0 (5.5) 444.5 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term $ 4,355.3 $ (5.7) 4,349.6 $ 4,397.3 $ (5.8) 4,391.5 Debt issuance cost (3) (29.6) (27.8) Long-term debt, net of unamortized issuance cost $ 4,320.0 $ 4,363.7 ____________________________ (1) The effective interest rate was 3.9% at December 31, 2021. (2) The effective interest rate was 2.8% and 1.2% at June 30, 2022 and December 31, 2021, respectively. (3) Net of accumulated amortization of $16.9 million and $18.4 million at June 30, 2022 and December 31, 2021, respectively. 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 under the Revolving Credit Facility 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. Borrowings under the Revolving Credit Facility bear interest at ENLC’s options at the Term SOFR plus a Term SOFR spread adjustment of 0.10% per annum 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%, the 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, amounts outstanding under the Revolving Credit Facility, if any, may become due and payable immediately. There were no outstanding borrowings under the Revolving Credit Facility and $44.6 million outstanding letters of credit as of June 30, 2022. At June 30, 2022, 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, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility. We are the primary beneficiary of the SPV and we consolidate its assets and liabilities, which consisted primarily of billed and unbilled accounts receivable of $946.7 million as of June 30, 2022. As of June 30, 2022, the AR Facility had a borrowing base of $350.0 million and there were $325.0 million in outstanding borrowings under the AR Facility. At June 30, 2022, 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. On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to $500.0 million and extend the scheduled termination date from September 24, 2024 to August 1, 2025. See “Item 5. Other Information” for additional information. Senior Unsecured Notes Repurchase For the three and six months ended June 30, 2022, we repurchased $2.0 million of ENLK’s outstanding senior unsecured notes due 2024 in open market transactions. We did not repurchase senior unsecured notes during the three and six months ended June 30, 2021.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2022
Income Tax Disclosure [Abstract]
Income Taxes	(6) Income Taxes The components of our total income tax benefit (expense) are as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Current income tax expense $ (0.5) $ — $ (0.7) $ (0.1) Deferred income tax benefit (expense) 1.8 (6.6) (1.2) (7.9) Total income tax benefit (expense) $ 1.3 $ (6.6) $ (1.9) $ (8.0) The following schedule reconciles total income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Expected income tax benefit (expense) based on federal statutory rate $ (17.8) $ 3.8 $ (25.9) $ 6.2 State income tax benefit (expense), net of federal benefit (2.5) 0.6 (3.6) 0.8 Unit-based compensation (1) — (0.4) (2.0) (2.9) Change in valuation allowance 21.0 (1.0) 28.1 (2.2) Oklahoma statutory rate change (2) — (7.6) — (7.6) Other 0.6 (2.0) 1.5 (2.3) Total income tax benefit (expense) $ 1.3 $ (6.6) $ (1.9) $ (8.0) ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of restricted incentive units. (2) Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4%. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the three and six months ended June 30, 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. As of June 30, 2022, we had $138.7 million of deferred tax liabilities, net of $511.9 million of deferred tax assets, which included a $123.5 million valuation allowance. As of December 31, 2021, we had $137.5 million of deferred tax liabilities, net of $481.6 million of deferred tax assets, which included a $151.6 million valuation allowance. A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. As of June 30, 2022, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

Certain Provisions of the ENLK

Certain Provisions of the ENLK Partnership Agreement	6 Months Ended
	Jun. 30, 2022
Partners' Capital [Abstract]
Certain Provisions of the ENLK Partnership Agreement	(7) Certain Provisions of the ENLK Partnership Agreement a. Series B Preferred Units As of June 30, 2022 and December 31, 2021, there were 54,168,359 and 57,501,693 Series B Preferred Units issued and outstanding, respectively. In January 2022, we redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2022 and 2021 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash distribution (in millions) Date paid/payable 2022 Fourth Quarter of 2021 — $ 19.2 February 11, 2022 (1) First Quarter of 2022 — $ 17.5 May 13, 2022 (2) Second Quarter of 2022 — $ 17.3 August 12, 2022 2021 Fourth Quarter of 2020 150,494 $ 16.9 February 12, 2021 First Quarter of 2021 150,871 $ 17.0 May 14, 2021 Second Quarter of 2021 151,248 $ 17.0 August 13, 2021 ____________________________ (1) In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed. (2) In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 was paid on May 13, 2022. b. Series C Preferred Units As of June 30, 2022 and December 31, 2021, there were 400,000 Series C Preferred Units issued and outstanding, respectively. ENLK distributed $12.0 million to holders of Series C Preferred Units during the three and six months ended June 30, 2022 and 2021, respectively.

Members' Equity

Members' Equity	6 Months Ended
	Jun. 30, 2022
Earnings Per Share [Abstract]
Members' Equity	(8) Members’ Equity a. Common Unit Repurchase Program In November 2020, the board of directors of the Managing Member (the “Board”) authorized a common unit repurchase program for the repurchase of up to $100.0 million of outstanding ENLC common units and reauthorized such program in April 2021. The Board reauthorized ENLC’s common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million effective January 1, 2022. In July 2022, the Board increased the amount available for repurchases to $200.0 million. 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. On February 15, 2022, we and GIP entered into an agreement 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 preceding quarter from public unitholders under our common unit repurchase program. See “Note 4—Related Party Transactions” above. The following table summarizes our ENLC common unit repurchase activity for the three and six months ended June 30, 2022 and 2021 (in millions, except for unit amounts): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Publicly held ENLC common units repurchased 2,921,370 317,751 5,015,212 317,751 ENLC common units held by GIP repurchased (1) 675,095 — 675,095 — Total ENLC common units repurchased 3,596,465 317,751 5,690,307 317,751 Aggregate cost for publicly held ENLC common units repurchased $ 27.7 $ 2.0 $ 44.7 $ 2.0 Aggregate cost for ENLC common units held by GIP repurchased (3) 6.0 — 6.0 — Total aggregate cost for ENLC common units repurchased $ 33.7 $ 2.0 $ 50.7 $ 2.0 ____________________________ (1) The units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. (2) For the three and six months ended June 30, 2022, the average price paid per common unit repurchased was $9.49 per common unit and $8.92 per common unit, respectively. For the three and six months ended June 30, 2021, the average price paid per common unit repurchased was $6.22 per common unit. (3) For the three and six months ended June 30, 2022, the average price paid per common unit repurchased was $8.92. The per unit price we paid to GIP was the average per unit price paid by us for publicly held ENLC common units repurchased from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. Additionally, on August 2, 2022, we repurchased 2,530,507 ENLC common units held by GIP at an aggregate cost of $24.0 million, or an average of $9.47 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended June 30, 2022. 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 commission, which were not paid with respect to the GIP units. b. Earnings Per Unit and Dilution Computations As required under ASC 260, Earnings Per Share , unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts): Three Months Ended Six Months Ended 2022 2021 2022 2021 Distributed earnings allocated to: Common units (1) $ 54.3 $ 46.0 $ 108.7 $ 91.9 Unvested restricted units (1) 1.4 1.1 2.5 2.2 Total distributed earnings $ 55.7 $ 47.1 $ 111.2 $ 94.1 Undistributed income (loss) allocated to: Common units $ 29.0 $ (67.1) $ 9.1 $ (125.4) Unvested restricted units 0.6 (1.6) 0.2 (3.0) Total undistributed income (loss) $ 29.6 $ (68.7) $ 9.3 $ (128.4) Net income (loss) attributable to ENLC allocated to: Common units $ 83.3 $ (21.1) $ 117.8 $ (33.5) Unvested restricted units 2.0 (0.5) 2.7 (0.8) Total net income (loss) attributable to ENLC $ 85.3 $ (21.6) $ 120.5 $ (34.3) Net income (loss) attributable to ENLC per unit: Basic $ 0.18 $ (0.04) $ 0.25 $ (0.07) Diluted $ 0.17 $ (0.04) $ 0.25 $ (0.07) ____________________________ (1) Represents distribution activity consistent with the distribution activity table below. The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Basic weighted average units outstanding: Weighted average common units outstanding 482.0 490.0 483.0 490.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 482.0 490.0 483.0 490.0 Dilutive effect of non-vested restricted units (1) 7.0 — 6.7 — Total weighted average diluted common units outstanding 489.0 490.0 489.7 490.0 ____________________________ (1) All common unit equivalents were antidilutive for the three and six months ended June 30, 2021, since a net loss existed for those periods. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. c. Distributions A summary of our distribution activity related to the ENLC common units for the six months ended June 30, 2022 and 2021, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2022 Fourth Quarter of 2021 $ 0.11250 February 11, 2022 First Quarter of 2022 $ 0.11250 May 13, 2022 Second Quarter of 2022 $ 0.11250 August 12, 2022 2021 Fourth Quarter of 2020 $ 0.09375 February 12, 2021 First Quarter of 2021 $ 0.09375 May 14, 2021 Second Quarter of 2021 $ 0.09375 August 13, 2021

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2022
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates On May 16, 2022, we formed a joint venture with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP (the “Matterhorn JV”) to construct a pipeline designed to transport up to 2.5 Bcf/d of natural gas through approximately 490 miles of 42-inch pipeline from the Waha Hub in West Texas to Katy, Texas (the “Matterhorn Express Pipeline”). As of June 30, 2022, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 GCF Contributions $ 0.5 $ — $ 0.5 $ — Distributions $ — $ — $ — $ (3.5) Equity in loss $ (0.9) $ (0.7) $ (1.6) $ (6.4) Cedar Cove JV Distributions $ (0.2) $ (0.1) $ (0.4) $ (0.2) Equity in loss $ (0.3) $ (0.6) $ (0.7) $ (1.2) Matterhorn JV Contributions $ 26.1 $ — $ 26.1 $ — Total Contributions $ 26.6 $ — $ 26.6 $ — Distributions $ (0.2) $ (0.1) $ (0.4) $ (3.7) Equity in loss $ (1.2) $ (1.3) $ (2.3) $ (7.6) The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2022 and December 31, 2021 (in millions): June 30, 2022 December 31, 2021 GCF $ 26.9 $ 28.0 Cedar Cove JV (1) (2.9) (1.8) Matterhorn JV 26.1 — Total investment in unconsolidated affiliates $ 50.1 $ 26.2 ____________________________

Employee Incentive Plans

Employee Incentive Plans	6 Months Ended
	Jun. 30, 2022
Share-Based Payment Arrangement [Abstract]
Employee Incentive Plans	(10) Employee Incentive Plans a. Long-Term Incentive Plans We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Cost of unit-based compensation charged to operating expense $ 1.2 $ 1.7 $ 2.8 $ 3.4 Cost of unit-based compensation charged to general and administrative expense 4.5 4.7 9.5 9.5 Total unit-based compensation expense $ 5.7 $ 6.4 $ 12.3 $ 12.9 Amount of related income tax benefit recognized in net income (1) $ 1.3 $ 1.5 $ 2.9 $ 3.0 ____________________________ (1) For the six months ended June 30, 2022, the amount of related income tax benefit recognized in net income excluded $2.0 million of income tax expense related to book-to-tax differences recorded upon the vesting of restricted units. For the three months ended June 30, 2022, there was no income tax expense related to book-to-tax differences recorded upon the vesting of units. For the three and six months ended June 30, 2021, the amount of related income tax benefit recognized in net income excluded $0.4 million and $2.9 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units. b. ENLC Restricted Incentive Units ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2022 is provided below: Six Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 7,507,471 $ 5.46 Granted (1) 2,386,493 8.81 Vested (1)(2) (1,100,302) 10.22 Forfeited (131,415) 5.91 Non-vested, end of period 8,662,247 $ 5.77 Aggregate intrinsic value, end of period (in millions) $ 73.6 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 296,453 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2022 and 2021 is provided below (in millions): Three Months Ended Six Months Ended ENLC Restricted Incentive Units: 2022 2021 2022 2021 Aggregate intrinsic value of units vested $ 0.6 $ 0.9 $ 8.2 $ 3.9 Fair value of units vested $ 0.5 $ 2.3 $ 11.2 $ 12.5 As of June 30, 2022, there were $25.7 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted-average period of 2.0 years. c. ENLC Performance Units ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. The following table presents a summary of the performance units: Six Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 3,574,827 $ 6.40 Granted 1,204,882 11.60 Vested (1) (708,361) 15.57 Non-vested, end of period 4,071,348 $ 6.34 Aggregate intrinsic value, end of period (in millions) $ 34.6 ____________________________ (1) Vested units included 273,357 units withheld for payroll taxes paid on behalf of employees. A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2022 and 2021 is provided below (in millions). Six Months Ended ENLC Performance Units: 2022 2021 Aggregate intrinsic value of units vested $ 5.6 $ 0.6 Fair value of units vested $ 11.0 $ 4.4 As of June 30, 2022, there were $20.3 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 2.0 years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: ENLC Performance Units: June 2022 March 2022 (1) January 2021 Grant-date fair value $ 11.71 $ 11.90 $ 4.70 Beginning TSR price $ 8.54 $ 8.83 $ 3.71 Risk-free interest rate 3.35 % 2.15 % 0.17 % Volatility factor 76.00 % 75.00 % 71.00 % ____________________________ (1) Excludes certain ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(11) Derivatives Interest Rate Swaps The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Change in fair value of interest rate swaps $ — $ 4.8 $ 0.1 $ 9.5 Tax expense — (1.1) — (2.2) Unrealized gain on designated cash flow hedge $ — $ 3.7 $ 0.1 $ 7.3 The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Interest expense $ — $ 4.8 $ 0.1 $ 9.6 We expect to recognize an additional $0.1 million of interest expense out of accumulated other comprehensive loss over the next twelve months. Commodity Swaps The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Change in fair value of derivatives $ 35.3 $ (23.8) $ 20.2 $ (31.7) Realized loss on derivatives (30.8) (14.4) (46.9) (89.9) Gain (loss) on derivative activity $ 4.5 $ (38.2) $ (26.7) $ (121.6) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): June 30, 2022 December 31, 2021 Fair value of derivative assets—current $ 95.6 $ 22.4 Fair value of derivative assets—long-term — 0.2 Fair value of derivative liabilities—current (88.7) (34.9) Fair value of derivative liabilities—long-term (1.2) (2.2) Net fair value of commodity swaps $ 5.7 $ (14.5) Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at June 30, 2022 (in millions). The remaining term of the contracts extend no later than July 2023. June 30, 2022 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gals (122.0) $ (4.1) Natural gas (short contracts) Swaps MMbtu (19.7) 26.8 Natural gas (long contracts) Swaps MMbtu 11.7 (19.5) Crude and condensate (short contracts) Swaps MMbbls (3.2) (55.4) Crude and condensate (long contracts) Swaps MMbbls 2.8 57.9 Total fair value of commodity swaps $ 5.7

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurements	(12) Fair Value Measurements Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2022 December 31, 2021 Commodity swaps (1) $ 5.7 $ (14.5) ____________________________ (1) The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820. Fair Value of Financial Instruments The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): June 30, 2022 December 31, 2021 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,320.0 $ 3,750.6 $ 4,363.7 $ 4,520.0 Installment payable (2) $ — $ — $ 10.0 $ 10.0 Contingent consideration (2) $ 7.2 $ 7.2 $ 6.9 $ 6.9 ____________________________ (1) The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $29.6 million and $27.8 million as of June 30, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs. (2) Consideration for the Amarillo Rattler Acquisition included a $10.0 million installment payable, which was paid on April 30, 2022, and 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. The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2022
Segment Reporting [Abstract]
Segment Information	(13) Segment Information We evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served: • Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico; • Louisiana Segment. The Louisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and our crude oil operations in ORV; • Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas; • North Texas Segment. The North Texas segment includes our natural gas gathering, processing, 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 and 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. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended June 30, 2022 Natural gas sales $ 323.0 $ 272.9 $ 87.1 $ 37.9 $ — $ 720.9 NGL sales — 1,163.7 3.6 0.1 — 1,167.4 Crude oil and condensate sales 331.6 110.0 40.6 — — 482.2 Product sales 654.6 1,546.6 131.3 38.0 — 2,370.5 NGL sales—related parties 427.5 43.1 242.6 165.8 (879.0) — Crude oil and condensate sales—related parties — — — 4.0 (4.0) — Product sales—related parties 427.5 43.1 242.6 169.8 (883.0) — Gathering and transportation 19.9 15.7 44.7 40.6 — 120.9 Processing 9.9 0.3 28.6 27.9 — 66.7 NGL services — 18.4 — 0.1 — 18.5 Crude services 6.0 9.2 3.2 0.2 — 18.6 Other services 0.2 0.4 0.1 0.2 — 0.9 Midstream services 36.0 44.0 76.6 69.0 — 225.6 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 1,118.1 1,633.7 450.6 276.8 (883.1) 2,596.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (958.0) (1,519.2) (321.3) (189.7) 883.1 (2,105.1) Realized loss on derivatives (10.2) (2.5) (15.8) (2.3) — (30.8) Change in fair value of derivatives 12.5 11.8 8.2 2.8 — 35.3 Adjusted gross margin 162.4 123.8 121.7 87.6 — 495.5 Operating expenses (50.3) (34.8) (23.1) (20.7) — (128.9) Segment profit 112.1 89.0 98.6 66.9 — 366.6 Depreciation and amortization (37.1) (39.4) (52.3) (28.7) (1.5) (159.0) Gain on disposition of assets — — 0.2 0.2 — 0.4 General and administrative — — — — (28.4) (28.4) Interest expense, net of interest income — — — — (55.5) (55.5) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (1.2) (1.2) Other income — — — — 0.2 0.2 Income (loss) before non-controlling interest and income taxes $ 75.0 $ 49.6 $ 46.5 $ 38.4 $ (86.9) $ 122.6 Capital expenditures $ 34.7 $ 6.3 $ 11.5 $ 8.1 $ 1.9 $ 62.5 ____________________________ (1) Includes related party cost of sales of $9.1 million for the three months ended June 30, 2022. Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended June 30, 2021 Natural gas sales $ 97.4 $ 122.0 $ 45.6 $ 26.2 $ — $ 291.2 NGL sales 0.5 706.6 0.4 (0.1) — 707.4 Crude oil and condensate sales 170.4 50.9 15.7 — — 237.0 Product sales 268.3 879.5 61.7 26.1 — 1,235.6 NGL sales—related parties 195.5 30.2 137.1 94.3 (457.1) — Crude oil and condensate sales—related parties — — 0.1 2.1 (2.2) — Product sales—related parties 195.5 30.2 137.2 96.4 (459.3) — Gathering and transportation 11.8 16.4 45.9 38.2 — 112.3 Processing 6.0 0.5 28.1 27.0 — 61.6 NGL services — 17.1 — 0.1 — 17.2 Crude services 4.0 9.6 3.4 0.2 — 17.2 Other services 0.2 0.4 0.2 0.2 — 1.0 Midstream services 22.0 44.0 77.6 65.7 — 209.3 Revenue from contracts with customers 485.8 953.7 276.5 188.2 (459.3) 1,444.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (402.3) (838.9) (164.9) (108.3) 459.3 (1,055.1) Realized loss on derivatives (4.2) (6.4) (2.9) (0.9) — (14.4) Change in fair value of derivatives (7.9) (9.4) (5.3) (1.2) — (23.8) Adjusted gross margin 71.4 99.0 103.4 77.8 — 351.6 Operating expenses (27.4) (31.7) (17.8) (19.9) — (96.8) Segment profit 44.0 67.3 85.6 57.9 — 254.8 Depreciation and amortization (34.6) (36.1) (50.6) (28.8) (1.8) (151.9) Gain on disposition of assets — 0.2 — 0.1 — 0.3 General and administrative — — — — (26.1) (26.1) Interest expense, net of interest income — — — — (60.0) (60.0) Loss from unconsolidated affiliate investments — — — — (1.3) (1.3) Other income — — — — 0.2 0.2 Income (loss) before non-controlling interest and income taxes $ 9.4 $ 31.4 $ 35.0 $ 29.2 $ (89.0) $ 16.0 Capital expenditures $ 39.5 $ 2.2 $ 4.9 $ 1.9 $ 0.1 $ 48.6 ____________________________ (1) Includes related party cost of sales of $3.6 million for the three months ended June 30, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2022 Natural gas sales $ 518.6 $ 484.4 $ 163.4 $ 63.3 $ — $ 1,229.7 NGL sales — 2,315.2 6.7 — — 2,321.9 Crude oil and condensate sales 603.6 183.9 75.3 — — 862.8 Product sales 1,122.2 2,983.5 245.4 63.3 — 4,414.4 NGL sales—related parties 827.3 80.0 450.7 312.7 (1,670.7) — Crude oil and condensate sales—related parties — — 0.3 7.0 (7.3) — Product sales—related parties 827.3 80.0 451.0 319.7 (1,678.0) — Gathering and transportation 33.5 32.0 87.4 79.4 — 232.3 Processing 17.7 0.8 54.0 55.5 — 128.0 NGL services — 42.3 — 0.1 — 42.4 Crude services 10.3 18.6 6.9 0.4 — 36.2 Other services 0.4 0.8 0.2 0.3 — 1.7 Midstream services 61.9 94.5 148.5 135.7 — 440.6 Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 0.1 — — (0.1) — Midstream services—related parties — 0.1 0.1 — (0.2) — Revenue from contracts with customers 2,011.4 3,158.1 845.0 518.7 (1,678.2) 4,855.0 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (1,724.7) (2,907.9) (598.1) (347.1) 1,678.2 (3,899.6) Realized loss on derivatives (12.6) (9.1) (19.5) (5.7) — (46.9) Change in fair value of derivatives 6.6 6.2 1.1 6.3 — 20.2 Adjusted gross margin 280.7 247.3 228.5 172.2 — 928.7 Operating expenses (95.6) (67.8) (44.1) (42.3) — (249.8) Segment profit 185.1 179.5 184.4 129.9 — 678.9 Depreciation and amortization (73.8) (74.9) (103.2) (57.1) (2.9) (311.9) Gain (loss) on disposition of assets — 0.2 0.4 (5.3) — (4.7) General and administrative — — — — (57.4) (57.4) Interest expense, net of interest income — — — — (110.6) (110.6) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (2.3) (2.3) Other income — — — — 0.3 0.3 Income (loss) before non-controlling interest and income taxes $ 111.3 $ 104.8 $ 81.6 $ 67.5 $ (173.4) $ 191.8 Capital expenditures $ 68.9 $ 12.0 $ 26.9 $ 11.2 $ 3.5 $ 122.5 ____________________________ (1) Includes related party cost of sales of $19.7 million for the six months ended June 30, 2022. Permian Louisiana Oklahoma North Texas Corporate Totals Six Months Ended June 30, 2021 Natural gas sales $ 222.4 $ 243.2 $ 81.5 $ 77.2 $ — $ 624.3 NGL sales 0.5 1,332.6 1.0 1.1 — 1,335.2 Crude oil and condensate sales 277.7 92.0 29.3 — — 399.0 Product sales 500.6 1,667.8 111.8 78.3 — 2,358.5 NGL sales—related parties 360.4 53.8 250.2 175.2 (839.6) — Crude oil and condensate sales—related parties — — 0.1 3.6 (3.7) — Product sales—related parties 360.4 53.8 250.3 178.8 (843.3) — Gathering and transportation 21.5 32.2 97.2 78.6 — 229.5 Processing 14.2 1.0 44.0 54.1 — 113.3 NGL services — 39.1 — 0.2 — 39.3 Crude services 7.5 19.5 6.7 0.4 — 34.1 Other services 0.4 0.9 0.4 0.3 — 2.0 Midstream services 43.6 92.7 148.3 133.6 — 418.2 Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 2.3 — — (2.3) — Midstream services—related parties — 2.3 0.1 — (2.4) — Revenue from contracts with customers 904.6 1,816.6 510.5 390.7 (845.7) 2,776.7 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (727.9) (1,579.3) (315.9) (212.4) 845.7 (1,989.8) Realized loss on derivatives (61.1) (17.1) (8.9) (2.8) — (89.9) Change in fair value of derivatives (13.2) (9.8) (7.1) (1.6) — (31.7) Adjusted gross margin 102.4 210.4 178.6 173.9 — 665.3 Operating expenses (15.6) (60.9) (37.5) (39.1) — (153.1) Segment profit 86.8 149.5 141.1 134.8 — 512.2 Depreciation and amortization (68.1) (72.2) (101.3) (57.5) (3.8) (302.9) Gain on disposition of assets 0.1 0.1 — 0.1 — 0.3 General and administrative — — — — (52.1) (52.1) Interest expense, net of interest income — — — — (120.0) (120.0) Loss from unconsolidated affiliate investments — — — — (7.6) (7.6) Other income — — — — 0.1 0.1 Income (loss) before non-controlling interest and income taxes $ 18.8 $ 77.4 $ 39.8 $ 77.4 $ (183.4) $ 30.0 Capital expenditures $ 52.8 $ 5.0 $ 6.8 $ 4.3 $ 0.5 $ 69.4 ____________________________ (1) Includes related party cost of sales of $6.8 million for the six months ended June 30, 2021. The table below represents information about segment assets as of June 30, 2022 and December 31, 2021 (in millions): Segment Identifiable Assets: June 30, 2022 December 31, 2021 Permian $ 2,525.8 $ 2,358.6 Louisiana 2,574.8 2,428.6 Oklahoma 2,581.1 2,619.5 North Texas 869.3 896.8 Corporate (1) 127.8 179.7 Total identifiable assets $ 8,678.8 $ 8,483.2 ____________________________

Other Information

Other Information	6 Months Ended
	Jun. 30, 2022
Other Liabilities Disclosure [Abstract]
Other Information	(14) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: June 30, 2022 December 31, 2021 Natural gas and NGLs inventory $ 124.9 $ 49.4 Prepaid expenses and other 34.8 34.2 Other current assets $ 159.7 $ 83.6 Other current liabilities: June 30, 2022 December 31, 2021 Accrued interest $ 47.2 $ 47.2 Accrued wages and benefits, including taxes 22.2 33.1 Accrued ad valorem taxes 24.3 28.3 Capital expenditure accruals 19.3 23.2 Short-term lease liability 21.2 18.1 Installment payable (1) — 10.0 Inactive easement commitment (2) 10.0 9.8 Operating expense accruals 14.2 9.6 Other 25.7 23.6 Other current liabilities $ 184.1 $ 202.9 ____________________________ (1) Consideration for the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022. (2) Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(15) Commitments and Contingencies In February 2021, the areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days (“Winter Storm Uri”). As a result of Winter Storm Uri, we have encountered customer billing disputes related to the delivery of gas during the storm, including one that resulted in litigation. The litigation is between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC (“Koch”) in the 162nd District Court in Dallas County, Texas. The dispute centers on whether EnLink Gas was excused from delivering gas or performing under certain delivery or purchase obligations during Winter Storm Uri, given our declaration of force majeure during the storm. Koch has invoiced us approximately $53.9 million (after subtracting amounts owed to EnLink Gas) and does not recognize the declaration of force majeure. We believe the declaration of force majeure was valid and appropriate and we intend to vigorously defend against Koch’s claims. Another of our subsidiaries, EnLink Energy GP, LLC, is also involved in litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currently pending in Harris County, Texas, in which multiple individual plaintiffs assert 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. We believe the claims against our subsidiary lack merit and we intend to vigorously defend against such claims. In addition, we are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations, or cash flows. We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2022
Subsequent Events [Abstract]
Subsequent Events	(16) Subsequent EventAcquisition of Barnett Shale Assets from Crestwood Equity Partners LP. On May 19, 2022, we entered into an agreement to acquire the North Texas gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for an upfront cash purchase price of approximately $275.0 million, plus an amount equal to the estimated working capital of approximately $14.5 million, subject to customary adjustments. These assets include approximately 500 miles of lean and rich gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. The acquisition closed on July 1, 2022. The initial accounting for this acquisition is not complete and therefore we cannot provide an estimated purchase price allocation as of the date of this report.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2022
Accounting Policies [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.
Revenue Recognition	Revenue RecognitionThe following table summarizes the contractually committed fees (in millions) that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Significant Accounting Polices

Significant Accounting Polices (Tables)	6 Months Ended
	Jun. 30, 2022
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 2022 (remaining) $ 69.6 2023 119.7 2024 99.9 2025 67.0 2026 59.9 Thereafter 290.9 Total $ 707.0

Intangible Assets (Tables)

Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Changes in Carrying Value	The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Six Months Ended June 30, 2022 Customer relationships, beginning of period $ 1,844.8 $ (795.1) $ 1,049.7 Amortization expense — (64.7) (64.7) Customer relationships, end of period $ 1,844.8 $ (859.8) $ 985.0
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2022 (remaining) $ 63.7 2023 127.6 2024 127.6 2025 110.2 2026 106.3 Thereafter 449.6 Total $ 985.0

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2022
Debt Disclosure [Abstract]
Summary of Debt	As of June 30, 2022 and December 31, 2021, long-term debt consisted of the following (in millions): June 30, 2022 December 31, 2021 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Revolving Credit Facility due 2027 (1) $ — $ — $ — $ 15.0 $ — $ 15.0 AR Facility due 2025 (2) 325.0 — 325.0 350.0 — 350.0 ENLK’s 4.40% Senior unsecured notes due 2024 519.8 0.5 520.3 521.8 0.7 522.5 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.3) 720.5 720.8 (0.4) 720.4 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.3) 490.7 491.0 (0.3) 490.7 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 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 (5.3) 444.7 450.0 (5.5) 444.5 ENLK’s 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term $ 4,355.3 $ (5.7) 4,349.6 $ 4,397.3 $ (5.8) 4,391.5 Debt issuance cost (3) (29.6) (27.8) Long-term debt, net of unamortized issuance cost $ 4,320.0 $ 4,363.7 ____________________________ (1) The effective interest rate was 3.9% at December 31, 2021. (2) The effective interest rate was 2.8% and 1.2% at June 30, 2022 and December 31, 2021, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2022
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our total income tax benefit (expense) are as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Current income tax expense $ (0.5) $ — $ (0.7) $ (0.1) Deferred income tax benefit (expense) 1.8 (6.6) (1.2) (7.9) Total income tax benefit (expense) $ 1.3 $ (6.6) $ (1.9) $ (8.0)
Reconciliation of Total Income Tax Expense to Income before Income Taxes	The following schedule reconciles total income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Expected income tax benefit (expense) based on federal statutory rate $ (17.8) $ 3.8 $ (25.9) $ 6.2 State income tax benefit (expense), net of federal benefit (2.5) 0.6 (3.6) 0.8 Unit-based compensation (1) — (0.4) (2.0) (2.9) Change in valuation allowance 21.0 (1.0) 28.1 (2.2) Oklahoma statutory rate change (2) — (7.6) — (7.6) Other 0.6 (2.0) 1.5 (2.3) Total income tax benefit (expense) $ 1.3 $ (6.6) $ (1.9) $ (8.0) ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of restricted incentive units. (2) Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4%. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the three and six months ended June 30, 2021 due to a remeasurement of deferred tax assets.

Certain Provisions of the ENL_2

Certain Provisions of the ENLK Partnership Agreement (Tables)	6 Months Ended
	Jun. 30, 2022
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2022 and 2021 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash distribution (in millions) Date paid/payable 2022 Fourth Quarter of 2021 — $ 19.2 February 11, 2022 (1) First Quarter of 2022 — $ 17.5 May 13, 2022 (2) Second Quarter of 2022 — $ 17.3 August 12, 2022 2021 Fourth Quarter of 2020 150,494 $ 16.9 February 12, 2021 First Quarter of 2021 150,871 $ 17.0 May 14, 2021 Second Quarter of 2021 151,248 $ 17.0 August 13, 2021 ____________________________ (1) In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed. (2) In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 was paid on May 13, 2022.

Members' Equity (Tables)

Members' Equity (Tables)	6 Months Ended
	Jun. 30, 2022
Earnings Per Share [Abstract]
GIP Repurchase Agreement	The following table summarizes our ENLC common unit repurchase activity for the three and six months ended June 30, 2022 and 2021 (in millions, except for unit amounts): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Publicly held ENLC common units repurchased 2,921,370 317,751 5,015,212 317,751 ENLC common units held by GIP repurchased (1) 675,095 — 675,095 — Total ENLC common units repurchased 3,596,465 317,751 5,690,307 317,751 Aggregate cost for publicly held ENLC common units repurchased $ 27.7 $ 2.0 $ 44.7 $ 2.0 Aggregate cost for ENLC common units held by GIP repurchased (3) 6.0 — 6.0 — Total aggregate cost for ENLC common units repurchased $ 33.7 $ 2.0 $ 50.7 $ 2.0 ____________________________ (1) The units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. (2) For the three and six months ended June 30, 2022, the average price paid per common unit repurchased was $9.49 per common unit and $8.92 per common unit, respectively. For the three and six months ended June 30, 2021, the average price paid per common unit repurchased was $6.22 per common unit.
Computation of Basic and Diluted Earnings per Limited Partner Unit	The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts): Three Months Ended Six Months Ended 2022 2021 2022 2021 Distributed earnings allocated to: Common units (1) $ 54.3 $ 46.0 $ 108.7 $ 91.9 Unvested restricted units (1) 1.4 1.1 2.5 2.2 Total distributed earnings $ 55.7 $ 47.1 $ 111.2 $ 94.1 Undistributed income (loss) allocated to: Common units $ 29.0 $ (67.1) $ 9.1 $ (125.4) Unvested restricted units 0.6 (1.6) 0.2 (3.0) Total undistributed income (loss) $ 29.6 $ (68.7) $ 9.3 $ (128.4) Net income (loss) attributable to ENLC allocated to: Common units $ 83.3 $ (21.1) $ 117.8 $ (33.5) Unvested restricted units 2.0 (0.5) 2.7 (0.8) Total net income (loss) attributable to ENLC $ 85.3 $ (21.6) $ 120.5 $ (34.3) Net income (loss) attributable to ENLC per unit: Basic $ 0.18 $ (0.04) $ 0.25 $ (0.07) Diluted $ 0.17 $ (0.04) $ 0.25 $ (0.07) ____________________________ (1) Represents distribution activity consistent with the distribution activity table below. The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Basic weighted average units outstanding: Weighted average common units outstanding 482.0 490.0 483.0 490.0 Diluted weighted average units outstanding: Weighted average basic common units outstanding 482.0 490.0 483.0 490.0 Dilutive effect of non-vested restricted units (1) 7.0 — 6.7 — Total weighted average diluted common units outstanding 489.0 490.0 489.7 490.0 ____________________________ (1) All common unit equivalents were antidilutive for the three and six months ended June 30, 2021, since a net loss existed for those periods.
Summary of Distribution Activity	A summary of our distribution activity related to the ENLC common units for the six months ended June 30, 2022 and 2021, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 2022 Fourth Quarter of 2021 $ 0.11250 February 11, 2022 First Quarter of 2022 $ 0.11250 May 13, 2022 Second Quarter of 2022 $ 0.11250 August 12, 2022 2021 Fourth Quarter of 2020 $ 0.09375 February 12, 2021 First Quarter of 2021 $ 0.09375 May 14, 2021 Second Quarter of 2021 $ 0.09375 August 13, 2021

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 2022
Equity Method Investments and Joint Ventures [Abstract]
Activity Related to Investment in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 GCF Contributions $ 0.5 $ — $ 0.5 $ — Distributions $ — $ — $ — $ (3.5) Equity in loss $ (0.9) $ (0.7) $ (1.6) $ (6.4) Cedar Cove JV Distributions $ (0.2) $ (0.1) $ (0.4) $ (0.2) Equity in loss $ (0.3) $ (0.6) $ (0.7) $ (1.2) Matterhorn JV Contributions $ 26.1 $ — $ 26.1 $ — Total Contributions $ 26.6 $ — $ 26.6 $ — Distributions $ (0.2) $ (0.1) $ (0.4) $ (3.7) Equity in loss $ (1.2) $ (1.3) $ (2.3) $ (7.6) The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2022 and December 31, 2021 (in millions): June 30, 2022 December 31, 2021 GCF $ 26.9 $ 28.0 Cedar Cove JV (1) (2.9) (1.8) Matterhorn JV 26.1 — Total investment in unconsolidated affiliates $ 50.1 $ 26.2 ____________________________

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	6 Months Ended
	Jun. 30, 2022
Share-Based Payment Arrangement [Abstract]
Schedule of Amounts Recognized in Consolidated Financial Statements	Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Cost of unit-based compensation charged to operating expense $ 1.2 $ 1.7 $ 2.8 $ 3.4 Cost of unit-based compensation charged to general and administrative expense 4.5 4.7 9.5 9.5 Total unit-based compensation expense $ 5.7 $ 6.4 $ 12.3 $ 12.9 Amount of related income tax benefit recognized in net income (1) $ 1.3 $ 1.5 $ 2.9 $ 3.0 ____________________________ (1) For the six months ended June 30, 2022, the amount of related income tax benefit recognized in net income excluded $2.0 million of income tax expense related to book-to-tax differences recorded upon the vesting of restricted units. For the three months ended June 30, 2022, there was no income tax expense related to book-to-tax differences recorded upon the vesting of units. For the three and six months ended June 30, 2021, the amount of related income tax benefit recognized in net income excluded $0.4 million and $2.9 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units.
Schedule Of Restricted Stock Units Activity, ENLC	A summary of the restricted incentive unit activity for the six months ended June 30, 2022 is provided below: Six Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 7,507,471 $ 5.46 Granted (1) 2,386,493 8.81 Vested (1)(2) (1,100,302) 10.22 Forfeited (131,415) 5.91 Non-vested, end of period 8,662,247 $ 5.77 Aggregate intrinsic value, end of period (in millions) $ 73.6 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units, Vested and Fair Value Vested, ENLC	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2022 and 2021 is provided below (in millions): Three Months Ended Six Months Ended ENLC Restricted Incentive Units: 2022 2021 2022 2021 Aggregate intrinsic value of units vested $ 0.6 $ 0.9 $ 8.2 $ 3.9 Fair value of units vested $ 0.5 $ 2.3 $ 11.2 $ 12.5
Summary of Performance Units, ENLC	The following table presents a summary of the performance units: Six Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 3,574,827 $ 6.40 Granted 1,204,882 11.60 Vested (1) (708,361) 15.57 Non-vested, end of period 4,071,348 $ 6.34 Aggregate intrinsic value, end of period (in millions) $ 34.6 ____________________________ (1) Vested units included 273,357 units withheld for payroll taxes paid on behalf of employees. A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2022 and 2021 is provided below (in millions). Six Months Ended ENLC Performance Units: 2022 2021 Aggregate intrinsic value of units vested $ 5.6 $ 0.6 Fair value of units vested $ 11.0 $ 4.4
Summary of Grant-Date Fair Values	The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: ENLC Performance Units: June 2022 March 2022 (1) January 2021 Grant-date fair value $ 11.71 $ 11.90 $ 4.70 Beginning TSR price $ 8.54 $ 8.83 $ 3.71 Risk-free interest rate 3.35 % 2.15 % 0.17 % Volatility factor 76.00 % 75.00 % 71.00 % ____________________________ (1) Excludes certain ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Change in fair value of interest rate swaps $ — $ 4.8 $ 0.1 $ 9.5 Tax expense — (1.1) — (2.2) Unrealized gain on designated cash flow hedge $ — $ 3.7 $ 0.1 $ 7.3 The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Interest expense $ — $ 4.8 $ 0.1 $ 9.6 The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended Six Months Ended 2022 2021 2022 2021 Change in fair value of derivatives $ 35.3 $ (23.8) $ 20.2 $ (31.7) Realized loss on derivatives (30.8) (14.4) (46.9) (89.9) Gain (loss) on derivative activity $ 4.5 $ (38.2) $ (26.7) $ (121.6)
Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps	The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): June 30, 2022 December 31, 2021 Fair value of derivative assets—current $ 95.6 $ 22.4 Fair value of derivative assets—long-term — 0.2 Fair value of derivative liabilities—current (88.7) (34.9) Fair value of derivative liabilities—long-term (1.2) (2.2) Net fair value of commodity swaps $ 5.7 $ (14.5)
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 swaps that we held for price risk management purposes and the related physical offsets at June 30, 2022 (in millions). The remaining term of the contracts extend no later than July 2023. June 30, 2022 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gals (122.0) $ (4.1) Natural gas (short contracts) Swaps MMbtu (19.7) 26.8 Natural gas (long contracts) Swaps MMbtu 11.7 (19.5) Crude and condensate (short contracts) Swaps MMbbls (3.2) (55.4) Crude and condensate (long contracts) Swaps MMbbls 2.8 57.9 Total fair value of commodity swaps $ 5.7

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2022
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 June 30, 2022 December 31, 2021 Commodity swaps (1) $ 5.7 $ (14.5) ____________________________
Schedule of the Estimated Fair Value of Financial Instruments	Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): June 30, 2022 December 31, 2021 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,320.0 $ 3,750.6 $ 4,363.7 $ 4,520.0 Installment payable (2) $ — $ — $ 10.0 $ 10.0 Contingent consideration (2) $ 7.2 $ 7.2 $ 6.9 $ 6.9 ____________________________ (1) The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $29.6 million and $27.8 million as of June 30, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2022
Segment Reporting [Abstract]
Summary of Financial Information	We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended June 30, 2022 Natural gas sales $ 323.0 $ 272.9 $ 87.1 $ 37.9 $ — $ 720.9 NGL sales — 1,163.7 3.6 0.1 — 1,167.4 Crude oil and condensate sales 331.6 110.0 40.6 — — 482.2 Product sales 654.6 1,546.6 131.3 38.0 — 2,370.5 NGL sales—related parties 427.5 43.1 242.6 165.8 (879.0) — Crude oil and condensate sales—related parties — — — 4.0 (4.0) — Product sales—related parties 427.5 43.1 242.6 169.8 (883.0) — Gathering and transportation 19.9 15.7 44.7 40.6 — 120.9 Processing 9.9 0.3 28.6 27.9 — 66.7 NGL services — 18.4 — 0.1 — 18.5 Crude services 6.0 9.2 3.2 0.2 — 18.6 Other services 0.2 0.4 0.1 0.2 — 0.9 Midstream services 36.0 44.0 76.6 69.0 — 225.6 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 1,118.1 1,633.7 450.6 276.8 (883.1) 2,596.1 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (958.0) (1,519.2) (321.3) (189.7) 883.1 (2,105.1) Realized loss on derivatives (10.2) (2.5) (15.8) (2.3) — (30.8) Change in fair value of derivatives 12.5 11.8 8.2 2.8 — 35.3 Adjusted gross margin 162.4 123.8 121.7 87.6 — 495.5 Operating expenses (50.3) (34.8) (23.1) (20.7) — (128.9) Segment profit 112.1 89.0 98.6 66.9 — 366.6 Depreciation and amortization (37.1) (39.4) (52.3) (28.7) (1.5) (159.0) Gain on disposition of assets — — 0.2 0.2 — 0.4 General and administrative — — — — (28.4) (28.4) Interest expense, net of interest income — — — — (55.5) (55.5) Loss on extinguishment of debt — — — — (0.5) (0.5) Loss from unconsolidated affiliate investments — — — — (1.2) (1.2) Other income — — — — 0.2 0.2 Income (loss) before non-controlling interest and income taxes $ 75.0 $ 49.6 $ 46.5 $ 38.4 $ (86.9) $ 122.6 Capital expenditures $ 34.7 $ 6.3 $ 11.5 $ 8.1 $ 1.9 $ 62.5 ____________________________ (1) Includes related party cost of sales of $9.1 million for the three months ended June 30, 2022. Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended June 30, 2021 Natural gas sales $ 97.4 $ 122.0 $ 45.6 $ 26.2 $ — $ 291.2 NGL sales 0.5 706.6 0.4 (0.1) — 707.4 Crude oil and condensate sales 170.4 50.9 15.7 — — 237.0 Product sales 268.3 879.5 61.7 26.1 — 1,235.6 NGL sales—related parties 195.5 30.2 137.1 94.3 (457.1) — Crude oil and condensate sales—related parties — — 0.1 2.1 (2.2) — Product sales—related parties 195.5 30.2 137.2 96.4 (459.3) — Gathering and transportation 11.8 16.4 45.9 38.2 — 112.3 Processing 6.0 0.5 28.1 27.0 — 61.6 NGL services — 17.1 — 0.1 — 17.2 Crude services 4.0 9.6 3.4 0.2 — 17.2 Other services 0.2 0.4 0.2 0.2 — 1.0 Midstream services 22.0 44.0 77.6 65.7 — 209.3 Revenue from contracts with customers 485.8 953.7 276.5 188.2 (459.3) 1,444.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (402.3) (838.9) (164.9) (108.3) 459.3 (1,055.1) Realized loss on derivatives (4.2) (6.4) (2.9) (0.9) — (14.4) Change in fair value of derivatives (7.9) (9.4) (5.3) (1.2) — (23.8) Adjusted gross margin 71.4 99.0 103.4 77.8 — 351.6 Operating expenses (27.4) (31.7) (17.8) (19.9) — (96.8) Segment profit 44.0 67.3 85.6 57.9 — 254.8 Depreciation and amortization (34.6) (36.1) (50.6) (28.8) (1.8) (151.9) Gain on disposition of assets — 0.2 — 0.1 — 0.3 General and administrative — — — — (26.1) (26.1) Interest expense, net of interest income — — — — (60.0) (60.0) Loss from unconsolidated affiliate investments — — — — (1.3) (1.3) Other income — — — — 0.2 0.2 Income (loss) before non-controlling interest and income taxes $ 9.4 $ 31.4 $ 35.0 $ 29.2 $ (89.0) $ 16.0 Capital expenditures $ 39.5 $ 2.2 $ 4.9 $ 1.9 $ 0.1 $ 48.6 ____________________________ (1) Includes related party cost of sales of $3.6 million for the three months ended June 30, 2021.
Schedule of Segment Assets	The table below represents information about segment assets as of June 30, 2022 and December 31, 2021 (in millions): Segment Identifiable Assets: June 30, 2022 December 31, 2021 Permian $ 2,525.8 $ 2,358.6 Louisiana 2,574.8 2,428.6 Oklahoma 2,581.1 2,619.5 North Texas 869.3 896.8 Corporate (1) 127.8 179.7 Total identifiable assets $ 8,678.8 $ 8,483.2 ____________________________

Other Information (Tables)

Other Information (Tables)	6 Months Ended
	Jun. 30, 2022
Other Liabilities Disclosure [Abstract]
Schedule of Other Current Liabilities	The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: June 30, 2022 December 31, 2021 Natural gas and NGLs inventory $ 124.9 $ 49.4 Prepaid expenses and other 34.8 34.2 Other current assets $ 159.7 $ 83.6 Other current liabilities: June 30, 2022 December 31, 2021 Accrued interest $ 47.2 $ 47.2 Accrued wages and benefits, including taxes 22.2 33.1 Accrued ad valorem taxes 24.3 28.3 Capital expenditure accruals 19.3 23.2 Short-term lease liability 21.2 18.1 Installment payable (1) — 10.0 Inactive easement commitment (2) 10.0 9.8 Operating expense accruals 14.2 9.6 Other 25.7 23.6 Other current liabilities $ 184.1 $ 202.9 ____________________________ (1) Consideration for the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022. (2) Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.

General (Details)

General (Details)		6 Months Ended
	May 16, 2022 Bcf / d mi	Jun. 30, 2022 Bcf / d processingPlant fractionator mi bbl
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of miles of pipeline | mi	490	12,100
Number of natural gas processing plants | processingPlant		22
Amount of processing capacity | Bcf / d	2.5	5.5
Number of fractionators | fractionator		7
Capacity of fractionators per day, barrels | bbl		320,000

Significant Accounting Polici_3

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Jun. 30, 2022 USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 707
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	707
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 69.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	6 months
Remaining performance obligations	$ 69.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 119.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 119.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 99.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 99.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 67
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 67
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 59.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Remaining performance obligations	$ 59.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 290.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	5 years
Remaining performance obligations	$ 290.9

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 31.9	$ 31.6	$ 64.7	$ 62.5
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)			10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)			20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets (in years)			14 years 10 months 24 days

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Finite-lived Intangible Assets [Roll Forward]
Gross carrying amount, beginning balance			$ 1,844.8
Accumulated amortization, beginning balance			(795.1)
Net carrying amount, beginning balance			1,049.7
Amortization expense	$ (31.9)	$ (31.6)	(64.7)	$ (62.5)
Gross carrying amount, ending balance	1,844.8		1,844.8
Accumulated amortization, ending balance	(859.8)		(859.8)
Net carrying amount, ending balance	$ 985		$ 985

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
2022	$ 63.7
2023	127.6
2024	127.6
2025	110.2
2026	106.3
Thereafter	449.6
Total	$ 985	$ 1,049.7

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	$ 2,105,100,000	$ 1,055,100,000	$ 3,899,600,000	$ 1,989,800,000
Accounts payable to related party		5,700,000		5,700,000		$ 1,600,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization		9,100,000	3,600,000	19,700,000	6,800,000
Accounts payable to related party		5,700,000		5,700,000		$ 1,600,000
GIP
Related Party Transaction [Line Items]
General and administrative expenses from transactions with related party		$ 0	$ 100,000	$ 0	$ 200,000
[1] Includes related party cost of sales of $9.1 million and $3.6 million for the three months ended June 30, 2022 and 2021, respectively, and $19.7 million and $6.8 million for the six months ended June 30, 2022 and 2021, respectively.

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Debt Instrument
Outstanding Principal	$ 4,355.3	$ 4,397.3
Premium (Discount)	(5.7)	(5.8)
Long-Term Debt	4,349.6	4,391.5
Debt issuance costs	(29.6)	(27.8)
Long-term debt, net of unamortized issuance cost	4,320	4,363.7
Debt issuance cost accumulated amortization	16.9	18.4
Revolving Credit Facility Due 2027
Debt Instrument
Outstanding Principal	0	15
Premium (Discount)	0	0
Long-Term Debt	0	$ 15
Effective interest rate (as a percent)		3.90%
AR Facility due 2024
Debt Instrument
Outstanding Principal	325	$ 350
Premium (Discount)	0	0
Long-Term Debt	$ 325	$ 350
Effective interest rate (as a percent)	2.80%	1.20%
4.4% Senior Notes Due 2024
Debt Instrument
Outstanding Principal	$ 519.8	$ 521.8
Premium (Discount)	0.5	0.7
Long-Term Debt	$ 520.3	522.5
Stated interest rate (as a percent)	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding Principal	$ 720.8	720.8
Premium (Discount)	(0.3)	(0.4)
Long-Term Debt	$ 720.5	720.4
Stated interest rate (as a percent)	4.15%
4.85 Senior Notes Due 2026
Debt Instrument
Outstanding Principal	$ 491	491
Premium (Discount)	(0.3)	(0.3)
Long-Term Debt	$ 490.7	490.7
Stated interest rate (as a percent)	4.85%
5.625% Senior unsecured notes due 2028
Debt Instrument
Outstanding Principal	$ 500	500
Premium (Discount)	0	0
Long-Term Debt	$ 500	500
Stated interest rate (as a percent)	5.625%
5.375% Senior Notes Due 2029
Debt Instrument
Outstanding Principal	$ 498.7	498.7
Premium (Discount)	0	0
Long-Term Debt	$ 498.7	498.7
Stated interest rate (as a percent)	5.375%
5.6% Senior Notes Due 2044
Debt Instrument
Outstanding Principal	$ 350	350
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 349.8	349.8
Stated interest rate (as a percent)	5.60%
5.05 Senior Notes Due 2045
Debt Instrument
Outstanding Principal	$ 450	450
Premium (Discount)	(5.3)	(5.5)
Long-Term Debt	$ 444.7	444.5
Stated interest rate (as a percent)	5.05%
Senior Notes, 5.45%, Due 2047
Debt Instrument
Outstanding Principal	$ 500	500
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9
Stated interest rate (as a percent)	5.45%

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($)				3 Months Ended		6 Months Ended
	Jun. 03, 2022	Jun. 02, 2022	Dec. 11, 2018	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Aug. 01, 2022
Debt Instrument
Loss on extinguishment of debt				$ 500,000	$ 0	$ 500,000	$ 0
Increase (decrease) in accounts receivable						946,700,000
Payments on borrowings						1,177,000,000	679,500,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity				350,000,000		350,000,000
Accounts receivable securitization facility, outstanding amount				325,000,000		325,000,000
Line of Credit | Asset-backed Securities | Subsequent Event
Debt Instrument
Maximum borrowing capacity								$ 500,000,000
Letters of credit
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%
Line of credit facility, fair value of amount outstanding				0		0
Letters of credit | Letter of Credit | ENLC
Debt Instrument
Line of credit facility, fair value of amount outstanding				44,600,000		$ 44,600,000
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Secured Overnight Financing Rate (SOFR) | Variable Rate Component One
Debt Instrument
Variable rate						0.10%
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Secured Overnight Financing Rate (SOFR) | Variable Rate Component Two
Debt Instrument
Variable rate						1%
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Secured Overnight Financing Rate (SOFR) | Minimum | Variable Rate Component One
Debt Instrument
Variable rate						1.125%
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Secured Overnight Financing Rate (SOFR) | Minimum | Variable Rate Component Two
Debt Instrument
Variable rate						0.125%
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Secured Overnight Financing Rate (SOFR) | Maximum | Variable Rate Component One
Debt Instrument
Variable rate						2%
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Secured Overnight Financing Rate (SOFR) | Maximum | Variable Rate Component Two
Debt Instrument
Variable rate						1%
Letters of credit | Line of Credit | EnLink Midstream Partners, LP | Base Rate | Variable Rate Component Two
Debt Instrument
Variable rate						0.50%
4.4% Senior Notes Due 2024
Debt Instrument
Payments on borrowings				$ 2,000,000	$ 0	$ 2,000,000	$ 0

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.5)	$ 0	$ (0.7)	$ (0.1)
Deferred income tax benefit (expense)	1.8	(6.6)	(1.2)	(7.9)
Total income tax benefit (expense)	1.3	(6.6)	(1.9)	(8)
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit (expense) based on federal statutory rate	(17.8)	3.8	(25.9)	6.2
State income tax benefit (expense), net of federal benefit	(2.5)	0.6	(3.6)	0.8
Unit-based compensation	0	(0.4)	(2)	(2.9)
Change in valuation allowance	21	(1)	28.1	(2.2)
Oklahoma statutory rate change	0	(7.6)	0	(7.6)
Other	0.6	(2)	1.5	(2.3)
Total income tax benefit (expense)	$ 1.3	(6.6)	$ (1.9)	(8)
Deferred state income tax expense (benefit)		$ (7.6)		$ 7.6

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ 138.7	$ 137.5
Deferred tax assets	511.9	481.6
Deferred tax assets, valuation allowance	$ 123.5	$ 151.6

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended						6 Months Ended
	Jan. 31, 2022	Dec. 31, 2021	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Jun. 30, 2022	Jun. 30, 2021
Partnership agreement
Total consideration paid									$ 50.5	$ 0
Series B Preferred Unitholders
Partnership agreement
Stock redeemed during period (in shares)	3,333,334
Total consideration paid	$ 50.5
Redemption price of preferred stock (as a percent)	101%
Distribution paid-in kind (in shares)			0	0	0	151,248	150,871	150,494
Cash distributions			$ 17.3	$ 17.5	$ 19.2	$ 17	$ 17	$ 16.9
Series B Preferred Unitholders | Limited Partner | Fourth Quarter of 2021
Partnership agreement
Distributions preferred units	$ 1	$ 0.9
Series B Preferred Unitholders | Limited Partner | First Quarter of 2022
Partnership agreement
Distributions preferred units	$ 0.3		$ 17.2
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		57,501,693	54,168,359		57,501,693				54,168,359
Preferred units, outstanding (in shares)		57,501,693	54,168,359		57,501,693				54,168,359
Series C Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)			12,000,000			12,000,000			12,000,000	12,000,000
Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)		400,000	400,000		400,000				400,000
Preferred units, outstanding (in shares)		400,000	400,000		400,000				400,000

Members' Equity - Narrative (De

Members' Equity - Narrative (Details) - USD ($)		3 Months Ended			6 Months Ended
	Aug. 02, 2022	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Jul. 31, 2022	Nov. 30, 2020
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Repurchase program, amount authorized								$ 100,000,000
Common units repurchased (in shares)		3,596,465		317,751	5,690,307	317,751
Common units repurchased		$ 33,700,000	$ 17,000,000	$ 2,000,000	$ 50,700,000	$ 2,000,000
Subsequent Event
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Repurchase program, amount authorized							$ 200,000,000
Common units repurchased (in shares)	2,530,507
Common units repurchased	$ 24,000,000
Shares repurchased, average cost per share (in dollars per share)	$ 9.47

Members' Equity - IP Repurchase

Members' Equity - IP Repurchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units repurchased (in shares)	3,596,465		317,751	5,690,307	317,751
Common units repurchased	$ 33.7	$ 17	$ 2	$ 50.7	$ 2
Public ENLC Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units repurchased (in shares)	2,921,370		317,751	5,015,212	317,751
Common units repurchased	$ 27.7		$ 2	$ 44.7	$ 2
Weighted average price of shares repurchased (in dollars per share)	$ 9.49		$ 6.22	$ 8.92	$ 6.22
ENCL Common Units Held by GIP
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units repurchased (in shares)	675,095		0	675,095	0
Common units repurchased	$ 6		$ 0	$ 6	$ 0
Weighted average price of shares repurchased (in dollars per share)	$ 8.92			$ 8.92

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Distributed earnings allocated to:
Total distributed earnings	$ 55.7	$ 47.1	$ 111.2	$ 94.1
Undistributed income (loss) allocated to:
Total undistributed loss, basic	29.6	(68.7)	9.3	(128.4)
Total undistributed loss, diluted	29.6	(68.7)	9.3	(128.4)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic	85.3	(21.6)	120.5	(34.3)
Total net income (loss), diluted	$ 85.3	$ (21.6)	$ 120.5	$ (34.3)
Net income (loss) attributable to ENLC per unit:
Basic (in dollars per share)	$ 0.18	$ (0.04)	$ 0.25	$ (0.07)
Diluted (in dollars per share)	$ 0.17	$ (0.04)	$ 0.25	$ (0.07)
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings	$ 1.4	$ 1.1	$ 2.5	$ 2.2
Undistributed income (loss) allocated to:
Total undistributed loss, basic	0.6	(1.6)	0.2	(3)
Total undistributed loss, diluted	0.6	(1.6)	0.2	(3)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic	2	(0.5)	2.7	(0.8)
Total net income (loss), diluted	2	(0.5)	2.7	(0.8)
Common units
Distributed earnings allocated to:
Total distributed earnings	54.3	46	108.7	91.9
Undistributed income (loss) allocated to:
Total undistributed loss, basic	29	(67.1)	9.1	(125.4)
Total undistributed loss, diluted	29	(67.1)	9.1	(125.4)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic	83.3	(21.1)	117.8	(33.5)
Total net income (loss), diluted	$ 83.3	$ (21.1)	$ 117.8	$ (33.5)

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in shares)	482	490	483	490
Dilutive effect of non-vested restricted units (in shares)	7	0	6.7	0
Total weighted average diluted common units outstanding (in shares)	489	490	489.7	490

Members' Equity - Distributions

Members' Equity - Distributions (Details) - $ / shares	3 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
Distribution declared/unit (in dollars per share)	$ 0.11250	$ 0.11250	$ 0.11250	$ 0.09375	$ 0.09375	$ 0.09375

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) $ in Millions		3 Months Ended		6 Months Ended
	May 16, 2022 Bcf / d mi	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($) Bcf / d mi	Jun. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
Equity method investments
Amount of processing capacity | Bcf / d	2.5			5.5
Number of miles of pipeline | mi	490			12,100
Contributions		$ 26.6	$ 0	$ 26.6	$ 0
Distributions		(0.2)	(0.1)	(0.4)	(3.7)
Loss from unconsolidated affiliate investments		(1.2)	(1.3)	(2.3)	(7.6)
Total investment in unconsolidated affiliates		$ 53		$ 53		$ 28
GCF
Equity method investments
Ownership interest		38.75%		38.75%
Contributions		$ 0.5	0	$ 0.5	0
Distributions		0	0	0	(3.5)
Loss from unconsolidated affiliate investments		$ (0.9)	(0.7)	$ (1.6)	(6.4)
Cedar Cove JV
Equity method investments
Ownership interest		30%		30%
Distributions		$ (0.2)	(0.1)	$ (0.4)	(0.2)
Loss from unconsolidated affiliate investments		$ (0.3)	(0.6)	$ (0.7)	(1.2)
Matterhorn JV
Equity method investments
Ownership interest		15%		15%
Contributions		$ 26.1	$ 0	$ 26.1	$ 0
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates		50.1		50.1		26.2
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates		26.9		26.9		28
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates		(2.9)		(2.9)		(1.8)
EnLink Midstream Partners, LP | Matterhorn JV
Equity method investments
Total investment in unconsolidated affiliates		$ 26.1		$ 26.1		$ 0

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Allocation
Total unit-based compensation expense	$ 5,700,000	$ 6,400,000	$ 12,300,000	$ 12,900,000
Amount of related income tax benefit recognized in net income	1,300,000	1,500,000	2,900,000	3,000,000
Unit-based compensation	0	400,000	2,000,000	2,900,000
Restricted units
Allocation
Unit-based compensation	0	400,000	2,000,000	2,900,000
Cost of unit-based compensation charged to operating expense
Allocation
Total unit-based compensation expense	1,200,000	1,700,000	2,800,000	3,400,000
Cost of unit-based compensation charged to general and administrative expense
Allocation
Total unit-based compensation expense	$ 4,500,000	$ 4,700,000	$ 9,500,000	$ 9,500,000

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			3 Months Ended		6 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jan. 31, 2021	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Unvested restricted units
Number of Units
Non-vested, beginning of period (in shares)						7,507,471
Granted (in shares)		193,935				2,386,493
Vested (in shares)						(1,100,302)
Forfeited (in shares)						(131,415)
Non-vested, end of period (in shares)	8,662,247			8,662,247		8,662,247
Aggregate intrinsic value, end of period	$ 73.6			$ 73.6		$ 73.6
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)						$ 5.46
Granted (in dollars per share)						8.81
Vested (in dollars per share)						10.22
Forfeited (in dollars per share)						5.91
Non-vested, end of period (in dollars per share)	$ 5.77			$ 5.77		$ 5.77
Incentive unit award vesting period						3 years
Units withheld for payroll taxes (in shares)						296,453
Aggregate intrinsic value of units vested				$ 0.6	$ 0.9	$ 8.2	$ 3.9
Fair value of units vested		$ 1.7		0.5	$ 2.3	11.2	12.5
Unrecognized compensation cost related to non-vested restricted incentive units	$ 25.7			$ 25.7		$ 25.7
Unrecognized compensation costs, weighted average period for recognition (in years)						2 years
ENLC Performance Units:
Grants in period		193,935				2,386,493
Performance units
Number of Units
Non-vested, beginning of period (in shares)						3,574,827
Granted (in shares)						1,204,882
Vested (in shares)						(708,361)
Non-vested, end of period (in shares)	4,071,348			4,071,348		4,071,348
Aggregate intrinsic value, end of period	$ 34.6			$ 34.6		$ 34.6
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)						$ 6.40
Granted (in dollars per share)						11.60
Vested (in dollars per share)						15.57
Non-vested, end of period (in dollars per share)	$ 6.34			$ 6.34		$ 6.34
Units withheld for payroll taxes (in shares)						273,357
Aggregate intrinsic value of units vested						$ 5.6	0.6
Fair value of units vested						11	$ 4.4
Unrecognized compensation cost related to non-vested restricted incentive units	$ 20.3			$ 20.3		$ 20.3
Unrecognized compensation costs, weighted average period for recognition (in years)						2 years
ENLC Performance Units:
Grant-date fair value (in dollars per share)	$ 11.71	$ 11.90	$ 4.70
Beginning TSR Price (in dollars per share)	$ 8.54	$ 8.83	$ 3.71
Risk-free interest rate (as a percent)	3.35%	2.15%	0.17%
Volatility factor (as a percent)	76%	75%	71%
Grants in period						1,204,882
Performance units | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting (as a percent)						0%
Performance units | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting (as a percent)						200%
Performance Shares With Vesting Conditions
Number of Units
Granted (in shares)						88,863
ENLC Performance Units:
Grant-date fair value (in dollars per share)		$ 8.90
Grants in period						88,863

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions	3 Months Ended							6 Months Ended
	Jun. 30, 2022		Mar. 31, 2022	Jun. 30, 2021		Mar. 31, 2021		Jun. 30, 2022		Jun. 30, 2021
Derivatives
Tax expense				$ (1.1)		$ (1.1)				$ (2.2)
Unrealized gain on designated cash flow hedge	$ 0	[1]	$ 0.1	3.7	[1],[2]	$ 3.6	[3]	$ 0.1	[1]	7.3	[1]
Interest expense	0			4.8				0.1		9.6
Interest expense expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	0.1							0.1
Interest rate swaps
Derivatives
Change in fair value of interest rate swaps	0			4.8				0.1		9.5
Tax expense	0			(1.1)				0		(2.2)
Unrealized gain on designated cash flow hedge	$ 0			$ 3.7				$ 0.1		$ 7.3
[1]Includes tax expense of $1.1 million and $2.2 million for the three and six months ended June 30, 2021, respectively.[2]Includes tax expense of $1.1 million.[3]Includes tax expense of $1.1 million.

Derivatives - Components of Com

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Derivatives
Change in fair value of derivatives	$ 35.3	$ (23.8)	$ 20.2	$ (31.7)
Gain (loss) on derivative activity	4.5	(38.2)	(26.7)	(121.6)
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	35.3	(23.8)	20.2	(31.7)
Realized loss on derivatives	(30.8)	(14.4)	(46.9)	(89.9)
Gain (loss) on derivative activity	$ 4.5	$ (38.2)	$ (26.7)	$ (121.6)

Derivatives - Fair Value of Com

Derivatives - Fair Value of Commodity Swap Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Derivatives
Fair value of derivative assets—current	$ 95.6	$ 22.4
Fair value of derivative assets—long-term	0	0.2
Fair value of derivative liabilities—current	(88.7)	(34.9)
Fair value of derivative liabilities—long-term	(1.2)	(2.2)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	95.6	22.4
Fair value of derivative assets—long-term	0	0.2
Fair value of derivative liabilities—current	(88.7)	(34.9)
Fair value of derivative liabilities—long-term	(1.2)	(2.2)
Net fair value of commodity swaps	$ 5.7	$ (14.5)

Derivatives - Commodity Swaps A

Derivatives - Commodity Swaps Additional Information (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) MMBTU MMBbls gal	Dec. 31, 2021 USD ($)
Derivatives
Net Fair Value	$ 5,700,000	$ (14,500,000)
Commodity
Derivatives
Net Fair Value	5,700,000
Maximum loss if counterparties fail to perform	95,600,000
Possible reduction in maximum loss if counterparties fail to perform	$ 9,600,000
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	122
Net Fair Value	$ (4,100,000)
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	19.7
Net Fair Value	$ 26,800,000
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	11.7
Net Fair Value	$ (19,500,000)
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	3.2
Net Fair Value	$ (55,400,000)
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	2.8
Net Fair Value	$ 57,900,000

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Level 2 | Commodity swaps | Recurring
Fair Value
Net Fair Value	$ 5.7	$ (14.5)

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021	Apr. 30, 2021
Fair Value
Debt issuance costs	$ 29.6	$ 27.8
Amarillo Rattler, LLC
Fair Value
Installment payable			$ 10
Business combination, maximum earnout			$ 15
Carrying Value
Fair Value
Long-term debt	4,320	4,363.7
Installment payable	0	10
Contingent consideration fair value	7.2	6.9
Fair Value
Fair Value
Long-term debt	3,750.6	4,520
Installment payable	0	10
Contingent consideration fair value	$ 7.2	$ 6.9

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Segment Reporting
Revenue from contracts with customers		$ 2,596.1	$ 1,444.9	$ 4,855	$ 2,776.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	(2,105.1)	(1,055.1)	(3,899.6)	(1,989.8)
Realized loss on derivatives		(30.8)	(14.4)	(46.9)	(89.9)
Change in fair value of derivatives		35.3	(23.8)	20.2	(31.7)
Adjusted gross margin		495.5	351.6	928.7	665.3
Operating expenses		(128.9)	(96.8)	(249.8)	(153.1)
Segment profit		366.6	254.8	678.9	512.2
Depreciation and amortization		(159)	(151.9)	(311.9)	(302.9)
Gain on disposition of assets		0.4	0.3	(4.7)	0.3
General and administrative		(28.4)	(26.1)	(57.4)	(52.1)
Interest expense, net of interest income		(55.5)	(60)	(110.6)	(120)
Loss on extinguishment of debt		(0.5)	0	(0.5)	0
Loss from unconsolidated affiliate investments		(1.2)	(1.3)	(2.3)	(7.6)
Other income		0.2	0.2	0.3	0.1
Income before non-controlling interest and income taxes		122.6	16	191.8	30
Capital expenditures		62.5	48.6	122.5	69.4
Related parties amount in cost of sales		9.1	3.6	19.7	6.8
Permian
Segment Reporting
Revenue from contracts with customers		1,118.1	485.8	2,011.4	904.6
Cost of sales, exclusive of operating expenses and depreciation and amortization		(958)	(402.3)	(1,724.7)	(727.9)
Realized loss on derivatives		(10.2)	(4.2)	(12.6)	(61.1)
Change in fair value of derivatives		12.5	(7.9)	6.6	(13.2)
Adjusted gross margin		162.4	71.4	280.7	102.4
Operating expenses		(50.3)	(27.4)	(95.6)	(15.6)
Segment profit		112.1	44	185.1	86.8
Depreciation and amortization		(37.1)	(34.6)	(73.8)	(68.1)
Gain on disposition of assets		0	0	0	0.1
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Loss on extinguishment of debt		0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		75	9.4	111.3	18.8
Capital expenditures		34.7	39.5	68.9	52.8
Louisiana
Segment Reporting
Revenue from contracts with customers		1,633.7	953.7	3,158.1	1,816.6
Cost of sales, exclusive of operating expenses and depreciation and amortization		(1,519.2)	(838.9)	(2,907.9)	(1,579.3)
Realized loss on derivatives		(2.5)	(6.4)	(9.1)	(17.1)
Change in fair value of derivatives		11.8	(9.4)	6.2	(9.8)
Adjusted gross margin		123.8	99	247.3	210.4
Operating expenses		(34.8)	(31.7)	(67.8)	(60.9)
Segment profit		89	67.3	179.5	149.5
Depreciation and amortization		(39.4)	(36.1)	(74.9)	(72.2)
Gain on disposition of assets		0	0.2	0.2	0.1
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Loss on extinguishment of debt		0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		49.6	31.4	104.8	77.4
Capital expenditures		6.3	2.2	12	5
Oklahoma
Segment Reporting
Revenue from contracts with customers		450.6	276.5	845	510.5
Cost of sales, exclusive of operating expenses and depreciation and amortization		(321.3)	(164.9)	(598.1)	(315.9)
Realized loss on derivatives		(15.8)	(2.9)	(19.5)	(8.9)
Change in fair value of derivatives		8.2	(5.3)	1.1	(7.1)
Adjusted gross margin		121.7	103.4	228.5	178.6
Operating expenses		(23.1)	(17.8)	(44.1)	(37.5)
Segment profit		98.6	85.6	184.4	141.1
Depreciation and amortization		(52.3)	(50.6)	(103.2)	(101.3)
Gain on disposition of assets		0.2	0	0.4	0
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Loss on extinguishment of debt		0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		46.5	35	81.6	39.8
Capital expenditures		11.5	4.9	26.9	6.8
North Texas
Segment Reporting
Revenue from contracts with customers		276.8	188.2	518.7	390.7
Cost of sales, exclusive of operating expenses and depreciation and amortization		(189.7)	(108.3)	(347.1)	(212.4)
Realized loss on derivatives		(2.3)	(0.9)	(5.7)	(2.8)
Change in fair value of derivatives		2.8	(1.2)	6.3	(1.6)
Adjusted gross margin		87.6	77.8	172.2	173.9
Operating expenses		(20.7)	(19.9)	(42.3)	(39.1)
Segment profit		66.9	57.9	129.9	134.8
Depreciation and amortization		(28.7)	(28.8)	(57.1)	(57.5)
Gain on disposition of assets		0.2	0.1	(5.3)	0.1
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Loss on extinguishment of debt		0		0
Loss from unconsolidated affiliate investments		0	0	0	0
Other income		0	0	0	0
Income before non-controlling interest and income taxes		38.4	29.2	67.5	77.4
Capital expenditures		8.1	1.9	11.2	4.3
Corporate
Segment Reporting
Revenue from contracts with customers		(883.1)	(459.3)	(1,678.2)	(845.7)
Cost of sales, exclusive of operating expenses and depreciation and amortization		883.1	459.3	1,678.2	845.7
Realized loss on derivatives		0	0	0	0
Change in fair value of derivatives		0	0	0	0
Adjusted gross margin		0	0	0	0
Operating expenses		0	0	0	0
Segment profit		0	0	0	0
Depreciation and amortization		(1.5)	(1.8)	(2.9)	(3.8)
Gain on disposition of assets		0	0	0	0
General and administrative		(28.4)	(26.1)	(57.4)	(52.1)
Interest expense, net of interest income		(55.5)	(60)	(110.6)	(120)
Loss on extinguishment of debt		(0.5)		(0.5)
Loss from unconsolidated affiliate investments		(1.2)	(1.3)	(2.3)	(7.6)
Other income		0.2	0.2	0.3	0.1
Income before non-controlling interest and income taxes		(86.9)	(89)	(173.4)	(183.4)
Capital expenditures		1.9	0.1	3.5	0.5
Product sales
Segment Reporting
Revenue from contracts with customers		2,370.5	1,235.6	4,414.4	2,358.5
Product sales | Permian
Segment Reporting
Revenue from contracts with customers		654.6	268.3	1,122.2	500.6
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers		1,546.6	879.5	2,983.5	1,667.8
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		131.3	61.7	245.4	111.8
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers		38	26.1	63.3	78.3
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers		720.9	291.2	1,229.7	624.3
Product sales, Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers		323	97.4	518.6	222.4
Product sales, Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers		272.9	122	484.4	243.2
Product sales, Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		87.1	45.6	163.4	81.5
Product sales, Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers		37.9	26.2	63.3	77.2
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers		1,167.4	707.4	2,321.9	1,335.2
Product sales, NGL sales | Permian
Segment Reporting
Revenue from contracts with customers		0	0.5	0	0.5
Product sales, NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers		1,163.7	706.6	2,315.2	1,332.6
Product sales, NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		3.6	0.4	6.7	1
Product sales, NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers		0.1	(0.1)	0	1.1
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers		482.2	237	862.8	399
Product sales, Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers		331.6	170.4	603.6	277.7
Product sales, Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers		110	50.9	183.9	92
Product sales, Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		40.6	15.7	75.3	29.3
Product sales, Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers		427.5	195.5	827.3	360.4
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		43.1	30.2	80	53.8
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		242.6	137.2	451	250.3
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		169.8	96.4	319.7	178.8
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(883)	(459.3)	(1,678)	(843.3)
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, NGL sales, related party | Permian
Segment Reporting
Revenue from contracts with customers		427.5	195.5	827.3	360.4
Product sales, NGL sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		43.1	30.2	80	53.8
Product sales, NGL sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		242.6	137.1	450.7	250.2
Product sales, NGL sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers		165.8	94.3	312.7	175.2
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(879)	(457.1)	(1,670.7)	(839.6)
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, Crude oil and condensate sales, related party | Permian
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, Crude oil and condensate sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Product sales, Crude oil and condensate sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		0	0.1	0.3	0.1
Product sales, Crude oil and condensate sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers		4	2.1	7	3.6
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(4)	(2.2)	(7.3)	(3.7)
Midstream services
Segment Reporting
Revenue from contracts with customers		225.6	209.3	440.6	418.2
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers		36	22	61.9	43.6
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers		44	44	94.5	92.7
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers		76.6	77.6	148.5	148.3
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers		69	65.7	135.7	133.6
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers		120.9	112.3	232.3	229.5
Midstream services, Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers		19.9	11.8	33.5	21.5
Midstream services, Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers		15.7	16.4	32	32.2
Midstream services, Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers		44.7	45.9	87.4	97.2
Midstream services, Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers		40.6	38.2	79.4	78.6
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers		66.7	61.6	128	113.3
Midstream services, Processing | Permian
Segment Reporting
Revenue from contracts with customers		9.9	6	17.7	14.2
Midstream services, Processing | Louisiana
Segment Reporting
Revenue from contracts with customers		0.3	0.5	0.8	1
Midstream services, Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers		28.6	28.1	54	44
Midstream services, Processing | North Texas
Segment Reporting
Revenue from contracts with customers		27.9	27	55.5	54.1
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers		18.5	17.2	42.4	39.3
Midstream services, NGL services | Permian
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers		18.4	17.1	42.3	39.1
Midstream services, NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, NGL services | North Texas
Segment Reporting
Revenue from contracts with customers		0.1	0.1	0.1	0.2
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers		18.6	17.2	36.2	34.1
Midstream services, Crude services | Permian
Segment Reporting
Revenue from contracts with customers		6	4	10.3	7.5
Midstream services, Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers		9.2	9.6	18.6	19.5
Midstream services, Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers		3.2	3.4	6.9	6.7
Midstream services, Crude services | North Texas
Segment Reporting
Revenue from contracts with customers		0.2	0.2	0.4	0.4
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers		0.9	1	1.7	2
Midstream services, Other services | Permian
Segment Reporting
Revenue from contracts with customers		0.2	0.2	0.4	0.4
Midstream services, Other services | Louisiana
Segment Reporting
Revenue from contracts with customers		0.4	0.4	0.8	0.9
Midstream services, Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1	0.2	0.2	0.4
Midstream services, Other services | North Texas
Segment Reporting
Revenue from contracts with customers		0.2	0.2	0.3	0.3
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers		0	$ 0	0	0
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0		0.1	2.3
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1		0.1	0.1
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(0.1)		(0.2)	(2.4)
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services, Crude services, related party | Permian
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services, Crude services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services, Crude services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1		0.1	0.1
Midstream services, Crude services, related party | North Texas
Segment Reporting
Revenue from contracts with customers		0		0	0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		$ (0.1)		(0.1)	(0.1)
Midstream services, Other services, related party
Segment Reporting
Revenue from contracts with customers				0	0
Midstream services, Other services, related party | Permian
Segment Reporting
Revenue from contracts with customers				0	0
Midstream services, Other services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers				0.1	2.3
Midstream services, Other services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers				0	0
Midstream services, Other services, related party | North Texas
Segment Reporting
Revenue from contracts with customers				0	0
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers				$ (0.1)	$ (2.3)
[1] Includes related party cost of sales of $9.1 million and $3.6 million for the three months ended June 30, 2022 and 2021, respectively, and $19.7 million and $6.8 million for the six months ended June 30, 2022 and 2021, respectively.

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Segment Reporting
Total identifiable assets	$ 8,678.8	$ 8,483.2
Permian
Segment Reporting
Total identifiable assets	2,525.8	2,358.6
Louisiana
Segment Reporting
Total identifiable assets	2,574.8	2,428.6
Oklahoma
Segment Reporting
Total identifiable assets	2,581.1	2,619.5
North Texas
Segment Reporting
Total identifiable assets	869.3	896.8
Corporate
Segment Reporting
Total identifiable assets	$ 127.8	$ 179.7

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Other current assets:
Natural gas and NGLs inventory	$ 124.9	$ 49.4
Prepaid expenses and other	34.8	34.2
Other current assets	159.7	83.6
Other current liabilities:
Accrued interest	47.2	47.2
Accrued wages and benefits, including taxes	22.2	33.1
Accrued ad valorem taxes	24.3	28.3
Capital expenditure accruals	19.3	23.2
Short-term lease liability	21.2	18.1
Installment payable	0	10
Inactive easement commitment	10	9.8
Operating expense accruals	14.2	9.6
Other	25.7	23.6
Other current liabilities	$ 184.1	$ 202.9

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) claim
Koch | EnLink Gas Marketing, LP
Commitments and Contingencies
Loss contingency, damages sought, value | $	$ 53.9
Harris County Multi-District Litigation | EnLink Energy GP, LLC
Commitments and Contingencies
Filed cases, over | claim	150

Subsequent Event (Details)

Subsequent Event (Details) $ in Millions			6 Months Ended
	Jul. 01, 2022 USD ($) MMcf / d plant mi	May 16, 2022 Bcf / d mi	Jun. 30, 2022 Bcf / d mi
Subsequent Event [Line Items]
Amount of processing capacity | Bcf / d		2.5	5.5
Number of miles of pipeline | mi		490	12,100
Subsequent Event | Crestwood Gas Services Operating LLC
Subsequent Event [Line Items]
Payments to acquire businesses | $	$ 275
Amount of processing capacity | MMcf / d	425
Working capital | $	$ 14.5
Number of miles of pipeline | mi	500
Number Of Processing Plants | plant	3