EnLink Midstream (ENLC) 10-Q 3 Nov 21 2021 Q3 Quarterly report Financial data

Cover Page

Cover Page - shares	9 Months Ended
	Sep. 30, 2021	Oct. 28, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
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)		487,957,616
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2021
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents		$ 36.1	$ 39.6
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.5, respectively		88.5	80.6
Accrued revenue and other		636.6	447.5
Fair value of derivative assets		75.3	25
Other current assets		156.2	58.7
Total current assets		992.7	651.4
Property and equipment, net of accumulated depreciation of $4,215.7 and $3,863.0, respectively		6,425.1	6,652.1
Intangible assets, net of accumulated amortization of $763.2 and $668.8, respectively		1,081.6	1,125.4
Investment in unconsolidated affiliates		29	41.6
Fair value of derivative assets		2.2	4.9
Other assets, net		95.9	75.5
Total assets		8,626.5	8,550.9
Current liabilities:
Accounts payable and drafts payable		103.5	60.5
Accrued gas, NGLs, condensate, and crude oil purchases	[1]	529.8	291.5
Fair value of derivative liabilities		110.9	37.1
Current maturities of long-term debt		150	349.8
Other current liabilities		215.9	149.1
Total current liabilities		1,110.1	888
Long-term debt		4,242.6	4,244
Other long-term liabilities		92.1	94.8
Deferred tax liability, net		124.2	108.6
Fair value of derivative liabilities		2.3	2.5
Members’ equity:
Members’ equity (487,951,939 and 489,381,149 units issued and outstanding, respectively)		1,338.8	1,508.8
Accumulated other comprehensive loss		(4.2)	(15.3)
Non-controlling interest		1,720.6	1,719.5
Total members’ equity		3,055.2	3,213
Commitments and contingencies (Note 15)
Total liabilities and members’ equity		$ 8,626.5	$ 8,550.9
[1]	Includes related party accounts payable balances of $1.9 million and $1.0 million at September 30, 2021 and December 31, 2020, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
ASSETS
Allowance for bad debt	$ 0.3	$ 0.5
Property and equipment, accumulated depreciation	4,215.7	3,863
Intangible assets, accumulated amortization	$ 763.2	$ 668.8
Members’ equity:
Common units issued (in shares)	487,951,939	489,381,149
Common units outstanding (in shares)	489,381,149	487,951,939
Accounts payable to related party	$ 1.9	$ 1

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Revenues:
Revenue from contracts with customers		$ 1,821.2	$ 933.6	$ 4,597.9	$ 2,837.8
Loss on derivative activity		(33.6)	(5.1)	(155.2)	(8.3)
Total revenues		1,787.6	928.5	4,442.7	2,829.5
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1],[2]	1,400.8	549.5	3,390.6	1,702.5
Operating expenses		106.9	94.3	260	283.1
Depreciation and amortization		153	160.3	455.9	481.3
Impairments		0	0	0	354.5
(Gain) loss on disposition of assets		(0.4)	(1.8)	(0.7)	2.8
General and administrative		28.2	25.7	80.3	79.6
Total operating costs and expenses		1,688.5	828	4,186.1	2,903.8
Operating income (loss)		99.1	100.5	256.6	(74.3)
Other income (expense):
Interest expense, net of interest income		(60.1)	(55.5)	(180.1)	(166.3)
Gain on extinguishment of debt		0	0	0	32
Income (loss) from unconsolidated affiliates		(2.3)	(0.2)	(9.9)	0.8
Other income		0	0.4	0.1	0.4
Total other expense		(62.4)	(55.3)	(189.9)	(133.1)
Income (loss) before non-controlling interest and income taxes		36.7	45.2	66.7	(207.4)
Income tax benefit (expense)		(4.4)	(6)	(12.4)	16
Net income (loss)		32.3	39.2	54.3	(191.4)
Net income attributable to non-controlling interest		30.4	26.6	86.7	78.7
Net income (loss) attributable to ENLC		$ 1.9	$ 12.6	$ (32.4)	$ (270.1)
Net income (loss) attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ 0	$ 0.03	$ (0.07)	$ (0.55)
Diluted common unit (in dollars per share)		$ 0	$ 0.03	$ (0.07)	$ (0.55)
Product sales
Revenues:
Revenue from contracts with customers		$ 1,610.2	$ 696.1	$ 3,968.7	$ 2,121.6
Midstream services
Revenues:
Revenue from contracts with customers		$ 211	$ 237.5	$ 629.2	$ 716.2
[1]	Includes related party cost of sales of $11.7 million and $6.2 million for the nine months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million and $475.5 million for the nine months ended September 30, 2021 and 2020, respectively.
[2]	Includes related party cost of sales of $4.9 million and $2.0 million for the three months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million and $158.6 million for the three months ended September 30, 2021 and 2020, respectively.

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Income Statement [Abstract]
Related party cost of sales	$ 4.9	$ 2	$ 11.7	$ 6.2
Depreciation and amortization	153	160.3	455.9	481.3
Operating Segments
Depreciation and amortization	$ 150.8	$ 158.6	$ 449.9	$ 475.5

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2021		Sep. 30, 2020		Sep. 30, 2021	Sep. 30, 2020
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 32.3		$ 39.2		$ 54.3	$ (191.4)
Unrealized gain (loss) on designated cash flow hedge	[1]	3.8	[2]	3.6	[3]	11.1	(8)
Comprehensive income (loss)		36.1		42.8		65.4	(199.4)
Comprehensive income attributable to non-controlling interest		30.4		26.6		86.7	78.7
Comprehensive income (loss) attributable to ENLC		$ 5.7		$ 16.2		$ (21.3)	$ (278.1)
[1]	Includes a tax expense of $1.2 million and a tax expense of $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and a tax expense of $3.4 million and a tax benefit of $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.
[2]	Includes a tax expense of $1.2 million.
[3]	Includes a tax expense of $1.1 million.

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended							9 Months Ended
	Sep. 30, 2021		Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ 1.2	[1]	$ 1.1	$ 1.1	$ 1.1	$ 0.5	$ (4)	$ 3.4	$ (2.4)
[1]	Includes a tax expense of $1.2 million and a tax expense of $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and a tax expense of $3.4 million and a tax benefit of $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.

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, 2019		$ 3,806.1		$ 2,135.5	$ (11)	$ 1,681.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2019				487,800,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(4)		$ (4)		0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				1,300,000
Unit-based compensation		12.3		$ 12.3		0
Contributions from non-controlling interests		37.1				37.1
Distributions		(117.7)		(93.3)		(24.4)	$ (0.3)
Unrealized gain (loss) on designated cash flow hedge	[1]	(13.1)			(13.1)
Fair value adjustment related to redeemable non-controlling interest		0.7		0.7			(0.9)
Net income (loss)		(260.4)		(286.8)		26.4	0
Member equity, end balance at Mar. 31, 2020		3,461		$ 1,764.4	(24.1)	1,720.7
Units outstanding, end balance (in shares) at Mar. 31, 2020				489,100,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2019							5.2
Increase (Decrease) in Temporary Equity
Distributions		(117.7)		$ (93.3)		(24.4)	(0.3)
Fair value adjustment related to redeemable non-controlling interest		0.7		0.7			(0.9)
Redemption of non-controlling interest							(4)
Redeemable noncontrolling interest, ending balance at Mar. 31, 2020							0
Member equity, beginning balance at Dec. 31, 2019		3,806.1		$ 2,135.5	(11)	1,681.6
Units outstanding, beginning balance (in shares) at Dec. 31, 2019				487,800,000
Increase (Decrease) in Members' Equity
Unrealized gain (loss) on designated cash flow hedge	[2]	(8)
Member equity, end balance at Sep. 30, 2020		3,411.1		$ 1,701.2	(19)	1,728.9
Units outstanding, end balance (in shares) at Sep. 30, 2020				489,700,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2019							5.2
Redeemable noncontrolling interest, ending balance at Sep. 30, 2020							0
Member equity, beginning balance at Mar. 31, 2020		3,461		$ 1,764.4	(24.1)	1,720.7
Units outstanding, beginning balance (in shares) at Mar. 31, 2020				489,100,000
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.3)		$ (0.3)		0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				400,000
Unit-based compensation		6.8		$ 6.8		0
Contributions from non-controlling interests		13.2				13.2
Distributions		(82.4)		(46.5)		(35.9)
Unrealized gain (loss) on designated cash flow hedge	[3]	1.5			1.5
Net income (loss)		29.8		4.1		25.7	0
Member equity, end balance at Jun. 30, 2020		3,429.6		$ 1,728.5	(22.6)	1,723.7
Units outstanding, end balance (in shares) at Jun. 30, 2020				489,500,000
Redeemable noncontrolling interest, beginning balance at Mar. 31, 2020							0
Increase (Decrease) in Temporary Equity
Distributions		(82.4)		$ (46.5)		(35.9)
Redeemable noncontrolling interest, ending balance at Jun. 30, 2020							0
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.4)		$ (0.4)		0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				200,000
Unit-based compensation		7.2		$ 7.2		0
Contributions from non-controlling interests		1.9				1.9
Distributions		(69.7)		(46.4)		(23.3)	(0.3)
Unrealized gain (loss) on designated cash flow hedge	[4]	3.6	[2]		3.6
Fair value adjustment related to redeemable non-controlling interest		(0.3)		(0.3)		0	0.3
Net income (loss)		39.2		12.6		26.6	0
Member equity, end balance at Sep. 30, 2020		3,411.1		$ 1,701.2	(19)	1,728.9
Units outstanding, end balance (in shares) at Sep. 30, 2020				489,700,000
Increase (Decrease) in Temporary Equity
Distributions		(69.7)		$ (46.4)		(23.3)	(0.3)
Fair value adjustment related to redeemable non-controlling interest		(0.3)		(0.3)		0	0.3
Redeemable noncontrolling interest, ending balance at Sep. 30, 2020							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		489,381,149		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 (loss) on designated cash flow hedge	[5]	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
Increase (Decrease) in Temporary Equity
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		489,381,149		489,400,000
Increase (Decrease) in Members' Equity
Unrealized gain (loss) on designated cash flow hedge	[2]	$ 11.1
Common units repurchased (in shares)		(2,394,296)
Member equity, end balance at Sep. 30, 2021		$ 3,055.2		$ 1,338.8	(4.2)	1,720.6
Units outstanding, end balance (in shares) at Sep. 30, 2021		487,951,939		488,000,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2020							0
Redeemable noncontrolling interest, ending balance at Sep. 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)	0
Unrealized gain (loss) on designated cash flow hedge	[6]	3.7			3.7
Common units repurchased		(2)		$ (2)
Common units repurchased (in shares)				(300,000)
Net income (loss)		9.4		$ (21.6)		31
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
Increase (Decrease) in Temporary Equity
Distributions		(82.7)		$ (46.7)		(36)	0
Redeemable noncontrolling interest, ending balance at Jun. 30, 2021							0
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(0.5)		$ (0.5)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)				200,000
Unit-based compensation		6.4		$ 6.4
Contributions from non-controlling interests		0.5				0.5
Distributions		(72.8)		(46.6)		(26.2)	0
Unrealized gain (loss) on designated cash flow hedge	[7]	3.8	[2]		3.8
Common units repurchased		$ (12.5)		$ (12.5)
Common units repurchased (in shares)		(2,076,545)		(2,100,000)
Net income (loss)		$ 32.3		$ 1.9		30.4
Member equity, end balance at Sep. 30, 2021		$ 3,055.2		$ 1,338.8	$ (4.2)	1,720.6
Units outstanding, end balance (in shares) at Sep. 30, 2021		487,951,939		488,000,000
Increase (Decrease) in Temporary Equity
Distributions		$ (72.8)		$ (46.6)		$ (26.2)	0
Redeemable noncontrolling interest, ending balance at Sep. 30, 2021							$ 0
[1]	Includes a tax benefit of $4.0 million.
[2]	Includes a tax expense of $1.2 million and a tax expense of $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and a tax expense of $3.4 million and a tax benefit of $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.
[3]	Includes a tax expense of $0.5 million.
[4]	Includes a tax expense of $1.1 million.
[5]	Includes a tax expense of $1.1 million.
[6]	Includes a tax expense of $1.1 million.
[7]	Includes a tax expense of $1.2 million.

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended							9 Months Ended
	Sep. 30, 2021		Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Statement of Stockholders' Equity [Abstract]
Income tax (benefit) expense	$ 1.2	[1]	$ 1.1	$ 1.1	$ 1.1	$ 0.5	$ (4)	$ 3.4	$ (2.4)
[1]	Includes a tax expense of $1.2 million and a tax expense of $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and a tax expense of $3.4 million and a tax benefit of $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash flows from operating activities:
Net income (loss)	$ 54.3	$ (191.4)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	0	354.5
Depreciation and amortization	455.9	481.3
Utility credits, net of usage	(38.2)	0
Deferred income tax (benefit) expense	12.2	(17.1)
Non-cash unit-based compensation	19.3	24.6
Amortization of designated cash flow hedge	9.6	0.1
Payments to terminate interest rate swaps	(1.8)	0
Non-cash loss on derivatives recognized in net income (loss)	37.5	7.3
Gain on extinguishment of debt	0	(32)
Amortization of debt issuance costs and net discount of senior unsecured notes	3.9	3.1
Other operating activities	6.8	2.8
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(196.5)	85.3
Natural gas and NGLs inventory, prepaid expenses, and other	(80.3)	(12.7)
Accounts payable, accrued product purchases, and other accrued liabilities	316.5	(144.8)
Net cash provided by operating activities	599.2	561
Cash flows from investing activities:
Additions to property and equipment	(104.7)	(254.4)
Acquisitions, net of cash acquired	(56.7)	0
Other investing activities	6	3.7
Net cash used in investing activities	(155.4)	(250.7)
Cash flows from financing activities:
Proceeds from borrowings	829.5	690
Repayments on borrowings	(1,034.5)	(776)
Distribution to members	(140.4)	(186.2)
Distributions to non-controlling interests	(88.2)	(84.2)
Contributions by non-controlling interests	2.4	52.2
Common unit repurchases	(14.5)	0
Other financing activities	(1.6)	(4.6)
Net cash used in financing activities	(447.3)	(308.8)
Net increase (decrease) in cash and cash equivalents	(3.5)	1.5
Cash and cash equivalents, beginning of period	39.6	77.4
Cash and cash equivalents, end of period	36.1	78.9
Supplemental disclosures of cash flow information:
Cash paid for interest	130.1	125.7
Cash paid (refunded) for income taxes	0.2	(0.1)
Non-cash investing activities:
Non-cash accrual of property and equipment	5.1	(27.2)
Non-cash acquisitions	16.9	0
Right-of-use assets obtained in exchange for operating lease liabilities	10.7	9.1
Non-cash financing activities:
Fair value adjustment related to redeemable non-controlling interest	$ 0	$ (4)

General

General	9 Months Ended
	Sep. 30, 2021
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. Our midstream energy asset network includes approximately 12,000 miles of pipelines, 23 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 290,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers. Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. c. COVID-19 Update On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. There remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic conditions and the extent and duration of changes in consumer behavior.

Significant Accounting Policies

Significant Accounting Policies	9 Months Ended
	Sep. 30, 2021
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, 2020. 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 (loss). 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. 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 (1) 2021 (remaining) $ 38.9 2022 136.3 2023 123.5 2024 107.6 2025 63.7 Thereafter 347.3 Total $ 817.3 ____________________________ (1) Amounts do not represent expected shortfall under these commitments. c. Acquisition of Business On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position with Diamondback Energy. We acquired the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10 million to be paid on April 30, 2022, and contingent consideration capped at $15 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels. Under the acquisition method of accounting, the acquired assets of Amarillo Rattler, LLC have been recorded at their respective fair values as of the date of the acquisition. Determining the fair value of the assets of Amarillo Ratter, LLC requires judgment and certain assumptions to be made, particularly related to the valuation of acquired customer relationships. The inputs and assumptions related to the customer relationships are categorized as level 3 in the fair value hierarchy. On a historical pro forma basis, our consolidated revenues, net income (loss), total assets, and earnings per unit amounts would not have differed materially had the acquisition been completed on January 1, 2021 rather than April 30, 2021. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 50.6 Installment payable 10.0 Contingent consideration fair value (1) 6.9 Total consideration: $ 67.5 Purchase price allocation Assets acquired: Current assets (including $1.3 million in cash) $ 1.4 Property and equipment 16.3 Intangible assets 50.6 Other assets, net (2) 0.6 Liabilities assumed: Current liabilities (0.8) Other long-term liabilities (2) (0.6) Net assets acquired $ 67.5 ____________________________ (1) The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820, Fair Value Measurements . There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from the estimated fair values.

Intangible Assets

Intangible Assets	9 Months Ended
	Sep. 30, 2021
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 following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Nine Months Ended September 30, 2021 Customer relationships, beginning of period $ 1,794.2 $ (668.8) $ 1,125.4 Customer relationships obtained from acquisition of business 50.6 — 50.6 Amortization expense — (94.4) (94.4) Customer relationships, end of period $ 1,844.8 $ (763.2) $ 1,081.6 The weighted average amortization period for intangible assets is 14.9 years. Amortization expense was $31.9 million and $30.9 million for the three months ended September 30, 2021 and 2020, respectively, and $94.4 million and $92.7 million for the nine months ended September 30, 2021 and 2020, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2021 (remaining) $ 31.9 2022 127.6 2023 127.6 2024 127.6 2025 110.3 Thereafter 556.6 Total $ 1,081.6

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2021
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions Transactions with Cedar Cove JV. For the three and nine months ended September 30, 2021, we recorded cost of sales of $4.9 million and $11.7 million, respectively, and for the three and nine months ended September 30, 2020, we recorded cost of sales of $2.0 million and $6.2 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 $1.9 million and $1.0 million at September 30, 2021 and December 31, 2020, respectively. Transactions with GIP . For the nine months ended September 30, 2021, we recorded general and administrative expenses of $0.2 million related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three months ended September 30, 2021. For each of the three and nine months ended September 30, 2020, we recorded general and administrative expenses of $0.2 million related to personnel secondment services provided by GIP.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2021
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of September 30, 2021 and December 31, 2020, long-term debt consisted of the following (in millions): September 30, 2021 December 31, 2020 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Term Loan due 2021 (1) $ 150.0 $ — $ 150.0 $ 350.0 $ — $ 350.0 Consolidated Credit Facility due 2024 — — — — — — AR Facility due 2024 (2) 245.0 — 245.0 250.0 — 250.0 ENLK’s 4.40% Senior unsecured notes due 2024 521.8 0.8 522.6 521.8 1.1 522.9 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.4) 720.4 720.8 (0.6) 720.2 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.3) 490.7 491.0 (0.4) 490.6 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 (5.6) 444.4 450.0 (5.7) 444.3 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 $ 4,427.3 $ (5.8) 4,421.5 $ 4,632.3 $ (5.9) 4,626.4 Debt issuance costs (3) (28.9) (32.6) Less: Current maturities of long-term debt (1) (150.0) (349.8) Long-term debt, net of unamortized issuance cost $ 4,242.6 $ 4,244.0 ____________________________ (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.6% and 1.7% at September 30, 2021 and December 31, 2020, respectively. The Term Loan will mature on December 10, 2021. Therefore, the outstanding principal balance, net of debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of September 30, 2021 and December 31, 2020, respectively. (2) Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.2% and 2.0% at September 30, 2021 and December 31, 2020, respectively. (3) Net of amortization of $17.5 million and $14.1 million at September 30, 2021 and December 31, 2020, respectively. Term Loan On December 11, 2018, ENLK entered into the Term Loan with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan and the outstanding balance becomes due, ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. In May 2021 and September 2021, we repaid $100.0 million and $100.0 million, respectively, of the borrowings under the Term Loan due December 2021. The outstanding balance of the Term Loan was $150.0 million as of September 30, 2021. The obligations under the Term Loan are unsecured. Under the terms of the Term Loan, if we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. In April 2021, we completed the acquisition of Amarillo Rattler, LLC with an aggregate purchase price in excess of $50.0 million and elected to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 through its maturity date. At September 30, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the Term Loan until the Term Loan matures on December 10, 2021. Consolidated Credit Facility The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC’s obligations under the Consolidated Credit Facility are accelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of the outstanding letters of credit under the Consolidated Credit Facility. There were no outstanding borrowings under the Consolidated Credit Facility and $41.1 million outstanding letters of credit as of September 30, 2021. Under the terms of the Consolidated Credit Facility, if we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. In April 2021, we completed the acquisition of Amarillo Rattler, LLC with an aggregate purchase price in excess of $50.0 million and elected to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 through the first quarter of 2022. At September 30, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the Consolidated 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 to borrow up to $250.0 million. In connection with the AR Facility, certain subsidiaries of ENLC sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. The SPV’s assets are not available to satisfy the obligations of ENLC or any of its affiliates. On February 26, 2021, the SPV entered into the first amendment to the AR Facility that, among other things: (i) increased the AR Facility limit and lender commitments by $50.0 million to $300.0 million, (ii) reduced the Adjusted LIBOR and LMIR (each as defined in the AR Facility) minimum floor to zero, rather than the previous 0.375%, and (iii) reduced the effective drawn fee to 1.25% rather than the previous 1.625%. On September 24, 2021, the SPV entered into the second amendment to the AR Facility that, among other things: (i) increased the AR Facility and lender commitments by $50.0 million to $350.0 million, (ii) extended the scheduled termination date of the facility from October 20, 2023 to September 24, 2024, and (iii) reduced the effective drawn fee to 1.10% rather than the previous 1.25%. Since our investment in the SPV is not sufficient to finance its activities without additional support from us, the SPV is a variable interest entity. We are the primary beneficiary of the SPV because we have the power to direct the activities that most significantly affect its economic performance and we are obligated to absorb its losses or receive its benefits from operations. Since we are the primary beneficiary of the SPV, we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $708.1 million and long-term debt of $245.0 million as of September 30, 2021. The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations. As of September 30, 2021, the AR Facility had a borrowing base of $350.0 million. Borrowings under the AR Facility bear interest (based on LIBOR or LMIR (as defined in the AR Facility)) plus a drawn fee in the amount of 1.10% at September 30, 2021. The SPV also pays a fee on the undrawn committed amount of the AR Facility. Interest and fees payable by the SPV under the AR Facility are due monthly. The AR Facility is scheduled to terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms, at which time no further advances will be available and the obligations under the AR Facility must be repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the AR Facility become due and payable. The AR Facility includes covenants, indemnification provisions, and events of default, including those providing for termination of the AR Facility and the acceleration of amounts owed by the SPV under the AR Facility if, among other things, a borrowing base deficiency exists, there is an event of default under the Consolidated Credit Facility, the Term Loan or certain other indebtedness, certain events negatively affecting the overall credit quality of the receivables held as collateral occur, a change of control occurs, or if the consolidated leverage ratio of ENLC exceeds limits identical to those in the Consolidated Credit Facility and the Term Loan. At September 30, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Income Taxes	(6) Income Taxes The components of our income tax benefit (expense) are as follows (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Current income tax expense $ (0.1) $ (0.4) $ (0.2) $ (1.1) Deferred income tax benefit (expense) (4.3) (5.6) (12.2) 17.1 Income tax benefit (expense) $ (4.4) $ (6.0) $ (12.4) $ 16.0 The following schedule reconciles total income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to income (loss) before income taxes (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Expected income tax benefit (expense) based on federal statutory rate $ (2.0) $ (3.6) $ 4.2 $ 60.0 State income tax benefit (expense), net of federal benefit (0.3) (0.6) 0.5 6.4 Unit-based compensation (1) (0.2) (1.6) (3.1) (6.0) Non-deductible expense related to goodwill impairment — — — (43.4) Change in valuation allowance (1.6) — (3.8) — Oklahoma statutory rate change (2) — — (7.6) — Other (0.3) (0.2) (2.6) (1.0) Income tax benefit (expense) $ (4.4) $ (6.0) $ (12.4) $ 16.0 ____________________________ (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%, effective January 1, 2022. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the nine months ended September 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 September 30, 2021, we had $124.2 million of deferred tax liabilities, net of $484.1 million of deferred tax assets, which included a $157.1 million valuation allowance. As of December 31, 2020, we had $108.6 million of deferred tax liabilities, net of $396.0 million of deferred tax assets, which included a $153.3 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 established a valuation allowance of $153.3 million as of December 31, 2020, 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. For the three and nine months ended September 30, 2021, we recorded a $1.6 million and $3.8 million valuation allowance adjustment, respectively. As of September 30, 2021, 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	9 Months Ended
	Sep. 30, 2021
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 September 30, 2021 and December 31, 2020, there were 60,650,397 and 60,197,784 Series B Preferred Units issued and outstanding, respectively. On August 4, 2021, Enfield Holdings, L.P. (“Enfield”) sold all of its Series B Preferred Units and Class C Common Units representing limited liability company interests in ENLC to Brookfield Infrastructure Partners and funds managed by Oaktree Capital Management, L.P. As a result of this sale, the right of holders of Series B Preferred Units and Class C Common Units to designate a representative to the board of directors of the Managing Member was terminated. A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2021 and 2020 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 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 Third Quarter of 2021 151,626 $ 17.1 November 12, 2021 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 Second Quarter of 2020 149,745 $ 16.8 August 13, 2020 Third Quarter of 2020 150,119 $ 16.9 November 13, 2020 b. Series C Preferred Units As of September 30, 2021 and December 31, 2020, 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 nine months ended September 30, 2021 and 2020, respectively.

Members' Equity

Members' Equity	9 Months Ended
	Sep. 30, 2021
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 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 repurchases 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”). The repurchases will depend on market conditions and may be discontinued at any time. For the three months ended September 30, 2021, ENLC repurchased 2,076,545 outstanding ENLC common units for an aggregate cost, including commissions, of $12.5 million, or an average of $6.02 per common unit. For the nine months ended September 30, 2021, ENLC repurchased 2,394,296 outstanding ENLC common units for an aggregate cost, including commissions, of $14.5 million, or an average of $6.05 per common unit. 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 Nine Months Ended 2021 2020 2021 2020 Distributed earnings allocated to: Common units (1) $ 45.8 $ 45.9 $ 137.7 $ 137.6 Unvested restricted units (1) 1.0 0.7 3.2 2.3 Total distributed earnings $ 46.8 $ 46.6 $ 140.9 $ 139.9 Undistributed loss allocated to: Common units $ (43.9) $ (33.4) $ (169.3) $ (403.0) Unvested restricted units (1.0) (0.6) (4.0) (7.0) Total undistributed loss $ (44.9) $ (34.0) $ (173.3) $ (410.0) Net income (loss) attributable to ENLC allocated to: Common units $ 1.9 $ 12.5 $ (31.6) $ (265.4) Unvested restricted units — 0.1 (0.8) (4.7) Total net income (loss) attributable to ENLC $ 1.9 $ 12.6 $ (32.4) $ (270.1) Basic and diluted total net income (loss) attributable to ENLC per unit: Basic $ — $ 0.03 $ (0.07) $ (0.55) Diluted $ — $ 0.03 $ (0.07) $ (0.55) ____________________________ (1) Represents distribution activity consistent with the distribution activity described in “ Distributions ” 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 Nine Months Ended 2021 2020 2021 2020 Basic weighted average units outstanding: Weighted average common units outstanding 488.6 489.7 489.6 489.2 Diluted weighted average units outstanding: Weighted average basic common units outstanding 488.6 489.7 489.6 489.2 Dilutive effect of non-vested restricted units (1) 6.2 1.2 — — Total weighted average diluted common units outstanding 494.8 490.9 489.6 489.2 ____________________________ (1) All common unit equivalents were antidilutive for the nine months ended September 30, 2021 and 2020, respectively, 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 nine months ended September 30, 2021 and 2020, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 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 Third Quarter of 2021 $ 0.09375 November 12, 2021 2020 Fourth Quarter of 2019 $ 0.1875 February 13, 2020 First Quarter of 2020 $ 0.09375 May 13, 2020 Second Quarter of 2020 $ 0.09375 August 13, 2020 Third Quarter of 2020 $ 0.09375 November 13, 2020

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2021
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates As of September 30, 2021, our unconsolidated investments consisted of a 38.75% ownership in GCF and a 30% ownership in the Cedar Cove JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 GCF Distributions $ — $ — $ 3.5 $ 1.6 Equity in income (loss) $ (1.7) $ 0.4 $ (8.1) $ 2.5 Cedar Cove JV Distributions $ 0.1 $ — $ 0.3 $ 0.4 Equity in loss $ (0.6) $ (0.6) $ (1.8) $ (1.7) Total Distributions $ 0.1 $ — $ 3.8 $ 2.0 Equity in income (loss) $ (2.3) $ (0.2) $ (9.9) $ 0.8 The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2021 and December 31, 2020 (in millions): September 30, 2021 December 31, 2020 GCF $ 29.0 $ 40.6 Cedar Cove JV (1) (1.1) 1.0 Total investment in unconsolidated affiliates $ 27.9 $ 41.6 ____________________________

Employee Incentive Plans

Employee Incentive Plans	9 Months Ended
	Sep. 30, 2021
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, Compensation—Stock Compensation , 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. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Cost of unit-based compensation charged to operating expense $ 1.5 $ 2.0 $ 4.9 $ 6.2 Cost of unit-based compensation charged to general and administrative expense 4.9 6.4 14.4 18.4 Total unit-based compensation expense $ 6.4 $ 8.4 $ 19.3 $ 24.6 Amount of related income tax benefit recognized in net income (loss) (1) $ 1.5 $ 2.0 $ 4.5 $ 5.8 ____________________________ (1) For the three and nine months ended September 30, 2021, the amount of related income tax benefit recognized in net income excluded $0.2 million and $3.1 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units. For the three and nine months ended September 30, 2020, the amount of related income tax benefit recognized in net income (loss) excluded $1.6 million and $6.0 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 nine months ended September 30, 2021 is provided below: Nine Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 5,350,086 $ 8.45 Granted (1) 3,926,541 3.85 Vested (1)(2) (1,234,251) 13.01 Forfeited (478,554) 6.11 Non-vested, end of period 7,563,822 $ 5.47 Aggregate intrinsic value, end of period (in millions) $ 51.6 ____________________________ (1) Restricted incentive units typically vest at the end of three years. (2) Vested units included 369,817 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 nine months ended September 30, 2021 and 2020 is provided below (in millions): Three Months Ended Nine Months Ended ENLC Restricted Incentive Units: 2021 2020 2021 2020 Aggregate intrinsic value of units vested $ 1.5 $ 1.0 $ 5.4 $ 11.9 Fair value of units vested $ 3.6 $ 6.0 $ 16.1 $ 31.0 As of September 30, 2021, there were $17.7 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 1.6 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: Nine Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 2,351,241 $ 8.82 Granted 1,388,139 4.70 Vested (1) (164,553) 26.73 Non-vested, end of period 3,574,827 $ 6.40 Aggregate intrinsic value, end of period (in millions) $ 24.4 ____________________________ (1) Vested units included 63,901 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 nine months ended September 30, 2021 and 2020 is provided below (in millions). No performance units vested for the three months ended September 30, 2021 and 2020. Nine Months Ended ENLC Performance Units: 2021 2020 Aggregate intrinsic value of units vested $ 0.6 $ 0.9 Fair value of units vested $ 4.4 $ 5.5 As of September 30, 2021, there were $9.7 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 1.7 years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: ENLC Performance Units: January 2021 July 2020 March 2020 January 2020 Grant-date fair value $ 4.70 $ 2.33 $ 1.13 $ 7.69 Beginning TSR price $ 3.71 $ 2.52 $ 1.25 $ 6.13 Risk-free interest rate 0.17 % 0.17 % 0.42 % 1.62 % Volatility factor 71.00 % 67.00 % 51.00 % 37.00 %

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(11) Derivatives Interest Rate Swaps In April 2019, we entered into $850.0 million of interest rate swaps to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we pay a fixed interest rate of 2.28% in exchange for LIBOR-based variable interest through December 2021. There was no ineffectiveness related to this hedge. In connection with the partial repayments of the Term Loan in September 2021, May 2021, and December 2020, we paid $0.5 million to terminate $100.0 million of the interest rate swaps, $1.3 million to terminate $100.0 million of the interest rate swaps, and $10.9 million to terminate $500.0 million of the interest rate swaps, respectively, for an aggregate termination of $700.0 million of the $850.0 million interest rate swaps and an aggregate settlement of $12.7 million of the outstanding derivative liability. The unrealized loss remains in accumulated other comprehensive income (loss) and will amortize into “Interest expense” on the consolidated statements of operations until the original maturity date of the Term Loan. For the three and nine months ended September 30, 2021, we amortized $3.5 million and $9.5 million, respectively, into interest expense out of accumulated other comprehensive income (loss) related to the partial terminations of the interest rate swaps. The remaining $150.0 million interest rate swaps were re-designated as a cash flow hedge on LIBOR-based borrowings and continue to be effective. The components of the unrealized gain (loss) 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 Nine Months Ended 2021 2020 2021 2020 Change in fair value of interest rate swaps $ 5.0 $ 4.7 $ 14.5 $ (10.4) Tax benefit (expense) (1.2) (1.1) (3.4) 2.4 Unrealized gain (loss) on designated cash flow hedge $ 3.8 $ 3.6 $ 11.1 $ (8.0) 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 Nine Months Ended 2021 2020 2021 2020 Interest expense $ 5.0 $ 4.6 $ 14.6 $ 9.6 We expect to recognize an additional $3.7 million of interest expense out of accumulated other comprehensive loss over the next twelve months. The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): September 30, 2021 December 31, 2020 Fair value of derivative liabilities—current $ (0.7) $ (7.6) Commodity Swaps The components of loss on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Change in fair value of derivatives $ (1.2) $ (2.2) $ (32.9) $ (8.0) Realized loss on derivatives (32.4) (2.9) (122.3) (0.3) Loss on derivative activity $ (33.6) $ (5.1) $ (155.2) $ (8.3) The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): September 30, 2021 December 31, 2020 Fair value of derivative assets—current $ 75.3 $ 25.0 Fair value of derivative assets—long-term 2.2 4.9 Fair value of derivative liabilities—current (110.2) (29.5) Fair value of derivative liabilities—long-term (2.3) (2.5) Net fair value of commodity swaps $ (35.0) $ (2.1) 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 September 30, 2021 (in millions). The remaining term of the contracts extend no later than January 2023. September 30, 2021 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (169.3) $ (56.3) NGL (long contracts) Swaps Gallons 7.8 1.4 Natural gas (short contracts) Swaps MMbtu (9.8) (17.6) Natural gas (long contracts) Swaps MMbtu 14.2 25.0 Crude and condensate (short contracts) Swaps MMbbls (7.8) (32.7) Crude and condensate (long contracts) Swaps MMbbls 3.8 45.2 Total fair value of commodity swaps $ (35.0)

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2021
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 September 30, 2021 December 31, 2020 Interest rate swaps (1) $ (0.7) $ (7.6) Commodity swaps (2) $ (35.0) $ (2.1) ____________________________ (1) The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. (2) The fair values of commodity 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 Measurement . 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): September 30, 2021 December 31, 2020 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,392.6 $ 4,466.7 $ 4,593.8 $ 4,318.2 Installment payable (2) $ 10.0 $ 10.0 $ — $ — Contingent consideration (2) $ 6.9 $ 6.9 $ — $ — ____________________________ (1) The carrying value of long-term debt includes current maturities and is reduced by debt issuance costs of $28.9 million and $32.6 million as of September 30, 2021 and December 31, 2020, respectively. The respective fair values do not factor in debt issuance costs. (2) Consideration paid for the acquisition of Amarillo Rattler, LLC included $10 million to be paid on April 30, 2022 and a contingent consideration capped at $15 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.” 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	9 Months Ended
	Sep. 30, 2021
Segment Reporting [Abstract]
Segment Information	(13) Segment Information Starting in the first quarter of 2021, we began evaluating 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. Commodity swaps activity was previously reported in the Corporate segment. We have recast segment information for all presented periods prior to the first quarter of 2021 to conform to current period presentation. 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, our ownership interest in GCF in South Texas, and our general 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 September 30, 2021 Natural gas sales $ 159.3 $ 183.2 $ 58.2 $ 32.2 $ — $ 432.9 NGL sales 0.4 898.6 0.3 (0.1) — 899.2 Crude oil and condensate sales 194.4 62.5 21.2 — — 278.1 Product sales 354.1 1,144.3 79.7 32.1 — 1,610.2 NGL sales—related parties 301.4 39.5 180.2 131.2 (652.3) — Crude oil and condensate sales—related parties — — — 1.5 (1.5) — Product sales—related parties 301.4 39.5 180.2 132.7 (653.8) — Gathering and transportation 12.8 16.3 44.6 39.0 — 112.7 Processing 7.5 0.9 26.5 27.0 — 61.9 NGL services — 16.9 — — — 16.9 Crude services 5.5 10.3 2.8 0.1 — 18.7 Other services 0.2 0.4 0.1 0.1 — 0.8 Midstream services 26.0 44.8 74.0 66.2 — 211.0 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 681.5 1,228.7 334.0 231.0 (654.0) 1,821.2 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (576.6) (1,110.8) (218.0) (149.4) 654.0 (1,400.8) Realized loss on derivatives (8.7) (14.9) (6.8) (2.0) — (32.4) Change in fair value of derivatives 10.2 (8.8) (2.3) (0.3) — (1.2) Adjusted gross margin 106.4 94.2 106.9 79.3 — 386.8 Operating expenses (37.3) (30.5) (19.8) (19.3) — (106.9) Segment profit 69.1 63.7 87.1 60.0 — 279.9 Depreciation and amortization (35.4) (34.6) (52.3) (28.5) (2.2) (153.0) Gain on disposition of assets 0.1 0.2 — 0.1 — 0.4 General and administrative — — — — (28.2) (28.2) Interest expense, net of interest income — — — — (60.1) (60.1) Loss from unconsolidated affiliates — — — — (2.3) (2.3) Income (loss) before non-controlling interest and income taxes $ 33.8 $ 29.3 $ 34.8 $ 31.6 $ (92.8) $ 36.7 Capital expenditures $ 25.8 $ 0.4 $ 10.3 $ 3.3 $ 0.6 $ 40.4 ____________________________ (1) Includes related party cost of sales of $4.9 million for the three months ended September 30, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million for the three months ended September 30, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended September 30, 2020 Natural gas sales $ 46.5 $ 76.4 $ 40.1 $ 16.0 $ — $ 179.0 NGL sales 0.1 402.3 1.2 — — 403.6 Crude oil and condensate sales 82.6 21.7 9.2 — — 113.5 Product sales 129.2 500.4 50.5 16.0 — 696.1 NGL sales—related parties 95.6 3.3 85.4 21.4 (205.7) — Crude oil and condensate sales—related parties — — — 0.7 (0.7) — Product sales—related parties 95.6 3.3 85.4 22.1 (206.4) — Gathering and transportation 17.9 10.7 56.7 43.4 — 128.7 Processing 8.0 0.3 32.4 33.3 — 74.0 NGL services — 14.2 — — — 14.2 Crude services 3.8 12.2 3.7 — — 19.7 Other services 0.2 0.4 0.1 0.2 — 0.9 Midstream services 29.9 37.8 92.9 76.9 — 237.5 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 254.7 541.5 228.9 115.0 (206.5) 933.6 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (185.4) (441.4) (101.0) (28.2) 206.5 (549.5) Realized loss on derivatives (0.4) (0.6) (1.7) (0.2) — (2.9) Change in fair value of derivatives 0.9 (2.7) (0.3) (0.1) — (2.2) Adjusted gross margin 69.8 96.8 125.9 86.5 — 379.0 Operating expenses (22.9) (31.1) (20.1) (20.2) — (94.3) Segment profit 46.9 65.7 105.8 66.3 — 284.7 Depreciation and amortization (31.9) (36.9) (53.0) (36.8) (1.7) (160.3) Gain on disposition of assets — — — 1.8 — 1.8 General and administrative — — — — (25.7) (25.7) Interest expense, net of interest income — — — — (55.5) (55.5) Loss from unconsolidated affiliates — — — — (0.2) (0.2) Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ 15.0 $ 28.8 $ 52.8 $ 31.3 $ (82.7) $ 45.2 Capital expenditures $ 28.5 $ 8.5 $ 2.6 $ 3.0 $ 0.6 $ 43.2 ____________________________ (1) Includes related party cost of sales of $2.0 million for the three months ended September 30, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $158.6 million for the three months ended September 30, 2020. Permian Louisiana Oklahoma North Texas Corporate Totals Nine Months Ended September 30, 2021 Natural gas sales $ 381.7 $ 426.4 $ 139.7 $ 109.4 $ — $ 1,057.2 NGL sales 0.9 2,231.2 1.3 1.0 — 2,234.4 Crude oil and condensate sales 472.1 154.5 50.5 — — 677.1 Product sales 854.7 2,812.1 191.5 110.4 — 3,968.7 NGL sales—related parties 661.8 93.3 430.4 306.4 (1,491.9) — Crude oil and condensate sales—related parties — — 0.1 5.1 (5.2) — Product sales—related parties 661.8 93.3 430.5 311.5 (1,497.1) — Gathering and transportation 34.3 48.5 141.8 117.6 — 342.2 Processing 21.7 1.9 70.5 81.1 — 175.2 NGL services — 56.0 — 0.2 — 56.2 Crude services 13.0 29.8 9.5 0.5 — 52.8 Other services 0.6 1.3 0.5 0.4 — 2.8 Midstream services 69.6 137.5 222.3 199.8 — 629.2 Crude services—related parties — — 0.2 — (0.2) — Other services—related parties — 2.4 — — (2.4) — Midstream services—related parties — 2.4 0.2 — (2.6) — Revenue from contracts with customers 1,586.1 3,045.3 844.5 621.7 (1,499.7) 4,597.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (1,304.5) (2,690.1) (533.9) (361.8) 1,499.7 (3,390.6) Realized loss on derivatives (69.8) (32.0) (15.7) (4.8) — (122.3) Change in fair value of derivatives (3.0) (18.6) (9.4) (1.9) — (32.9) Adjusted gross margin 208.8 304.6 285.5 253.2 — 1,052.1 Operating expenses (52.9) (91.4) (57.3) (58.4) — (260.0) Segment profit 155.9 213.2 228.2 194.8 — 792.1 Depreciation and amortization (103.5) (106.8) (153.6) (86.0) (6.0) (455.9) Gain on disposition of assets 0.2 0.3 — 0.2 — 0.7 General and administrative — — — — (80.3) (80.3) Interest expense, net of interest income — — — — (180.1) (180.1) Loss from unconsolidated affiliates — — — — (9.9) (9.9) Other income — — — — 0.1 0.1 Income (loss) before non-controlling interest and income taxes $ 52.6 $ 106.7 $ 74.6 $ 109.0 $ (276.2) $ 66.7 Capital expenditures $ 78.6 $ 5.4 $ 17.1 $ 7.6 $ 1.1 $ 109.8 ____________________________ (1) Includes related party cost of sales of $11.7 million for the nine months ended September 30, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million for the nine months ended September 30, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Nine Months Ended September 30, 2020 Natural gas sales $ 94.0 $ 226.6 $ 110.0 $ 50.7 $ — $ 481.3 NGL sales 0.2 1,056.9 2.9 0.3 — 1060.3 Crude oil and condensate sales 454.6 95.0 30.4 — — 580.0 Product sales 548.8 1,378.5 143.3 51.0 — 2,121.6 NGL sales—related parties 201.0 13.3 209.0 52.5 (475.8) — Crude oil and condensate sales—related parties 0.1 — (0.1) 2.6 (2.6) — Product sales—related parties 201.1 13.3 208.9 55.1 (478.4) — Gathering and transportation 47.3 33.9 165.5 133.5 — 380.2 Processing 19.8 1.6 97.8 101.7 — 220.9 NGL services — 52.4 — 0.1 — 52.5 Crude services 13.0 33.8 12.6 — — 59.4 Other services 1.0 1.2 0.3 0.7 — 3.2 Midstream services 81.1 122.9 276.2 236.0 — 716.2 Crude services—related parties — — 0.3 — (0.3) — Midstream services—related parties — — 0.3 — (0.3) — Revenue from contracts with customers 831.0 1,514.7 628.7 342.1 (478.7) 2,837.8 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (637.7) (1,213.6) (255.8) (74.1) 478.7 (1,702.5) Realized gain (loss) on derivatives (0.6) 1.9 (1.7) 0.1 — (0.3) Change in fair value of derivatives 2.3 (7.8) (2.4) (0.1) — (8.0) Adjusted gross margin 195.0 295.2 368.8 268.0 — 1,127.0 Operating expenses (71.1) (90.4) (62.4) (59.2) — (283.1) Segment profit 123.9 204.8 306.4 208.8 — 843.9 Depreciation and amortization (92.1) (109.3) (163.7) (110.4) (5.8) (481.3) Impairments (184.6) (169.9) — — — (354.5) Gain (loss) on disposition of assets (4.9) 0.1 0.1 1.9 — (2.8) General and administrative — — — — (79.6) (79.6) Interest expense, net of interest income — — — — (166.3) (166.3) Gain on extinguishment of debt — — — — 32.0 32.0 Income from unconsolidated affiliates — — — — 0.8 0.8 Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ (157.7) $ (74.3) $ 142.8 $ 100.3 $ (218.5) $ (207.4) Capital expenditures $ 161.4 $ 39.3 $ 14.1 $ 10.7 $ 1.7 $ 227.2 ____________________________ (1) Includes related party cost of sales of $6.2 million for the nine months ended September 30, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $475.5 million for the nine months ended September 30, 2020. The table below represents information about segment assets as of September 30, 2021 and December 31, 2020 (in millions): Segment Identifiable Assets: September 30, 2021 December 31, 2020 Permian $ 2,391.2 $ 2,236.3 Louisiana 2,489.4 2,312.4 Oklahoma 2,661.5 2,847.6 North Texas 938.0 1,008.6 Corporate (1) 146.4 146.0 Total identifiable assets $ 8,626.5 $ 8,550.9 ____________________________

Other Information

Other Information	9 Months Ended
	Sep. 30, 2021
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: September 30, 2021 December 31, 2020 Natural gas and NGLs inventory $ 116.6 $ 44.9 Prepaid expenses and other 39.6 13.8 Other current assets $ 156.2 $ 58.7 Other current liabilities: September 30, 2021 December 31, 2020 Accrued interest $ 71.7 $ 35.7 Accrued wages and benefits, including taxes 26.0 22.5 Accrued ad valorem taxes 32.4 26.5 Capital expenditure accruals 15.0 10.6 Short-term lease liability 15.8 16.3 Operating expense accruals 11.7 8.4 Other 43.3 29.1 Other current liabilities $ 215.9 $ 149.1

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2021
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 several pending customer billing disputes, including one that has resulted in litigation, and we could be involved in other disputes and litigation arising out of the storm in the future.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2021
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, 2020. 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 (loss). 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. 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)	9 Months Ended
	Sep. 30, 2021
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. 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 (1) 2021 (remaining) $ 38.9 2022 136.3 2023 123.5 2024 107.6 2025 63.7 Thereafter 347.3 Total $ 817.3 ____________________________ (1) Amounts do not represent expected shortfall under these commitments.
Schedule of Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions): Consideration Cash (including working capital payment) $ 50.6 Installment payable 10.0 Contingent consideration fair value (1) 6.9 Total consideration: $ 67.5 Purchase price allocation Assets acquired: Current assets (including $1.3 million in cash) $ 1.4 Property and equipment 16.3 Intangible assets 50.6 Other assets, net (2) 0.6 Liabilities assumed: Current liabilities (0.8) Other long-term liabilities (2) (0.6) Net assets acquired $ 67.5 ____________________________ (1) The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820, Fair Value Measurements . There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from the estimated fair values.

Intangible Assets (Tables)

Intangible Assets (Tables)	9 Months Ended
	Sep. 30, 2021
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 Nine Months Ended September 30, 2021 Customer relationships, beginning of period $ 1,794.2 $ (668.8) $ 1,125.4 Customer relationships obtained from acquisition of business 50.6 — 50.6 Amortization expense — (94.4) (94.4) Customer relationships, end of period $ 1,844.8 $ (763.2) $ 1,081.6
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2021 (remaining) $ 31.9 2022 127.6 2023 127.6 2024 127.6 2025 110.3 Thereafter 556.6 Total $ 1,081.6

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2021
Debt Disclosure [Abstract]
Summary of Debt	As of September 30, 2021 and December 31, 2020, long-term debt consisted of the following (in millions): September 30, 2021 December 31, 2020 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Term Loan due 2021 (1) $ 150.0 $ — $ 150.0 $ 350.0 $ — $ 350.0 Consolidated Credit Facility due 2024 — — — — — — AR Facility due 2024 (2) 245.0 — 245.0 250.0 — 250.0 ENLK’s 4.40% Senior unsecured notes due 2024 521.8 0.8 522.6 521.8 1.1 522.9 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.4) 720.4 720.8 (0.6) 720.2 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.3) 490.7 491.0 (0.4) 490.6 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 (5.6) 444.4 450.0 (5.7) 444.3 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 $ 4,427.3 $ (5.8) 4,421.5 $ 4,632.3 $ (5.9) 4,626.4 Debt issuance costs (3) (28.9) (32.6) Less: Current maturities of long-term debt (1) (150.0) (349.8) Long-term debt, net of unamortized issuance cost $ 4,242.6 $ 4,244.0 ____________________________ (1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.6% and 1.7% at September 30, 2021 and December 31, 2020, respectively. The Term Loan will mature on December 10, 2021. Therefore, the outstanding principal balance, net of debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of September 30, 2021 and December 31, 2020, respectively. (2) Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.2% and 2.0% at September 30, 2021 and December 31, 2020, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax benefit (expense) are as follows (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Current income tax expense $ (0.1) $ (0.4) $ (0.2) $ (1.1) Deferred income tax benefit (expense) (4.3) (5.6) (12.2) 17.1 Income tax benefit (expense) $ (4.4) $ (6.0) $ (12.4) $ 16.0
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 (loss) before income taxes (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Expected income tax benefit (expense) based on federal statutory rate $ (2.0) $ (3.6) $ 4.2 $ 60.0 State income tax benefit (expense), net of federal benefit (0.3) (0.6) 0.5 6.4 Unit-based compensation (1) (0.2) (1.6) (3.1) (6.0) Non-deductible expense related to goodwill impairment — — — (43.4) Change in valuation allowance (1.6) — (3.8) — Oklahoma statutory rate change (2) — — (7.6) — Other (0.3) (0.2) (2.6) (1.0) Income tax benefit (expense) $ (4.4) $ (6.0) $ (12.4) $ 16.0 ____________________________ (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%, effective January 1, 2022. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the nine months ended September 30, 2021 due to a remeasurement of deferred tax assets.

Certain Provisions of the ENL_2

Certain Provisions of the ENLK Partnership Agreement (Tables)	9 Months Ended
	Sep. 30, 2021
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2021 and 2020 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 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 Third Quarter of 2021 151,626 $ 17.1 November 12, 2021 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 Second Quarter of 2020 149,745 $ 16.8 August 13, 2020 Third Quarter of 2020 150,119 $ 16.9 November 13, 2020

Members' Equity (Tables)

Members' Equity (Tables)	9 Months Ended
	Sep. 30, 2021
Earnings Per Share [Abstract]
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 Nine Months Ended 2021 2020 2021 2020 Distributed earnings allocated to: Common units (1) $ 45.8 $ 45.9 $ 137.7 $ 137.6 Unvested restricted units (1) 1.0 0.7 3.2 2.3 Total distributed earnings $ 46.8 $ 46.6 $ 140.9 $ 139.9 Undistributed loss allocated to: Common units $ (43.9) $ (33.4) $ (169.3) $ (403.0) Unvested restricted units (1.0) (0.6) (4.0) (7.0) Total undistributed loss $ (44.9) $ (34.0) $ (173.3) $ (410.0) Net income (loss) attributable to ENLC allocated to: Common units $ 1.9 $ 12.5 $ (31.6) $ (265.4) Unvested restricted units — 0.1 (0.8) (4.7) Total net income (loss) attributable to ENLC $ 1.9 $ 12.6 $ (32.4) $ (270.1) Basic and diluted total net income (loss) attributable to ENLC per unit: Basic $ — $ 0.03 $ (0.07) $ (0.55) Diluted $ — $ 0.03 $ (0.07) $ (0.55) ____________________________ (1) Represents distribution activity consistent with the distribution activity described in “ Distributions ” 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 Nine Months Ended 2021 2020 2021 2020 Basic weighted average units outstanding: Weighted average common units outstanding 488.6 489.7 489.6 489.2 Diluted weighted average units outstanding: Weighted average basic common units outstanding 488.6 489.7 489.6 489.2 Dilutive effect of non-vested restricted units (1) 6.2 1.2 — — Total weighted average diluted common units outstanding 494.8 490.9 489.6 489.2 ____________________________ (1) All common unit equivalents were antidilutive for the nine months ended September 30, 2021 and 2020, respectively, 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 nine months ended September 30, 2021 and 2020, respectively, is provided below: Declaration period Distribution/unit Date paid/payable 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 Third Quarter of 2021 $ 0.09375 November 12, 2021 2020 Fourth Quarter of 2019 $ 0.1875 February 13, 2020 First Quarter of 2020 $ 0.09375 May 13, 2020 Second Quarter of 2020 $ 0.09375 August 13, 2020 Third Quarter of 2020 $ 0.09375 November 13, 2020

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2021
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 Nine Months Ended 2021 2020 2021 2020 GCF Distributions $ — $ — $ 3.5 $ 1.6 Equity in income (loss) $ (1.7) $ 0.4 $ (8.1) $ 2.5 Cedar Cove JV Distributions $ 0.1 $ — $ 0.3 $ 0.4 Equity in loss $ (0.6) $ (0.6) $ (1.8) $ (1.7) Total Distributions $ 0.1 $ — $ 3.8 $ 2.0 Equity in income (loss) $ (2.3) $ (0.2) $ (9.9) $ 0.8 The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2021 and December 31, 2020 (in millions): September 30, 2021 December 31, 2020 GCF $ 29.0 $ 40.6 Cedar Cove JV (1) (1.1) 1.0 Total investment in unconsolidated affiliates $ 27.9 $ 41.6 ____________________________

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 2021
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 Nine Months Ended 2021 2020 2021 2020 Cost of unit-based compensation charged to operating expense $ 1.5 $ 2.0 $ 4.9 $ 6.2 Cost of unit-based compensation charged to general and administrative expense 4.9 6.4 14.4 18.4 Total unit-based compensation expense $ 6.4 $ 8.4 $ 19.3 $ 24.6 Amount of related income tax benefit recognized in net income (loss) (1) $ 1.5 $ 2.0 $ 4.5 $ 5.8 ____________________________
Schedule Of Restricted Stock Units Activity, ENLC	A summary of the restricted incentive unit activity for the nine months ended September 30, 2021 is provided below: Nine Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 5,350,086 $ 8.45 Granted (1) 3,926,541 3.85 Vested (1)(2) (1,234,251) 13.01 Forfeited (478,554) 6.11 Non-vested, end of period 7,563,822 $ 5.47 Aggregate intrinsic value, end of period (in millions) $ 51.6 ____________________________ (1) Restricted incentive units typically vest at the end of three years.
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 nine months ended September 30, 2021 and 2020 is provided below (in millions): Three Months Ended Nine Months Ended ENLC Restricted Incentive Units: 2021 2020 2021 2020 Aggregate intrinsic value of units vested $ 1.5 $ 1.0 $ 5.4 $ 11.9 Fair value of units vested $ 3.6 $ 6.0 $ 16.1 $ 31.0
Summary of Performance Units, ENLC	The following table presents a summary of the performance units: Nine Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 2,351,241 $ 8.82 Granted 1,388,139 4.70 Vested (1) (164,553) 26.73 Non-vested, end of period 3,574,827 $ 6.40 Aggregate intrinsic value, end of period (in millions) $ 24.4 ____________________________ (1) Vested units included 63,901 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 nine months ended September 30, 2021 and 2020 is provided below (in millions). No performance units vested for the three months ended September 30, 2021 and 2020. Nine Months Ended ENLC Performance Units: 2021 2020 Aggregate intrinsic value of units vested $ 0.6 $ 0.9 Fair value of units vested $ 4.4 $ 5.5
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: January 2021 July 2020 March 2020 January 2020 Grant-date fair value $ 4.70 $ 2.33 $ 1.13 $ 7.69 Beginning TSR price $ 3.71 $ 2.52 $ 1.25 $ 6.13 Risk-free interest rate 0.17 % 0.17 % 0.42 % 1.62 % Volatility factor 71.00 % 67.00 % 51.00 % 37.00 %

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of the unrealized gain (loss) on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Change in fair value of interest rate swaps $ 5.0 $ 4.7 $ 14.5 $ (10.4) Tax benefit (expense) (1.2) (1.1) (3.4) 2.4 Unrealized gain (loss) on designated cash flow hedge $ 3.8 $ 3.6 $ 11.1 $ (8.0) 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 Nine Months Ended 2021 2020 2021 2020 Interest expense $ 5.0 $ 4.6 $ 14.6 $ 9.6 The components of loss on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended Nine Months Ended 2021 2020 2021 2020 Change in fair value of derivatives $ (1.2) $ (2.2) $ (32.9) $ (8.0) Realized loss on derivatives (32.4) (2.9) (122.3) (0.3) Loss on derivative activity $ (33.6) $ (5.1) $ (155.2) $ (8.3)
Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps	The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): September 30, 2021 December 31, 2020 Fair value of derivative liabilities—current $ (0.7) $ (7.6)
Schedule Of 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): September 30, 2021 December 31, 2020 Fair value of derivative assets—current $ 75.3 $ 25.0 Fair value of derivative assets—long-term 2.2 4.9 Fair value of derivative liabilities—current (110.2) (29.5) Fair value of derivative liabilities—long-term (2.3) (2.5) Net fair value of commodity swaps $ (35.0) $ (2.1)
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 September 30, 2021 (in millions). The remaining term of the contracts extend no later than January 2023. September 30, 2021 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (169.3) $ (56.3) NGL (long contracts) Swaps Gallons 7.8 1.4 Natural gas (short contracts) Swaps MMbtu (9.8) (17.6) Natural gas (long contracts) Swaps MMbtu 14.2 25.0 Crude and condensate (short contracts) Swaps MMbbls (7.8) (32.7) Crude and condensate (long contracts) Swaps MMbbls 3.8 45.2 Total fair value of commodity swaps $ (35.0)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2021
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 September 30, 2021 December 31, 2020 Interest rate swaps (1) $ (0.7) $ (7.6) Commodity swaps (2) $ (35.0) $ (2.1) ____________________________ (1) The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. (2) The fair values of commodity 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 Measurement .
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): September 30, 2021 December 31, 2020 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,392.6 $ 4,466.7 $ 4,593.8 $ 4,318.2 Installment payable (2) $ 10.0 $ 10.0 $ — $ — Contingent consideration (2) $ 6.9 $ 6.9 $ — $ — ____________________________ (1) The carrying value of long-term debt includes current maturities and is reduced by debt issuance costs of $28.9 million and $32.6 million as of September 30, 2021 and December 31, 2020, respectively. The respective fair values do not factor in debt issuance costs. (2) Consideration paid for the acquisition of Amarillo Rattler, LLC included $10 million to be paid on April 30, 2022 and a contingent consideration capped at $15 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2021
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 September 30, 2021 Natural gas sales $ 159.3 $ 183.2 $ 58.2 $ 32.2 $ — $ 432.9 NGL sales 0.4 898.6 0.3 (0.1) — 899.2 Crude oil and condensate sales 194.4 62.5 21.2 — — 278.1 Product sales 354.1 1,144.3 79.7 32.1 — 1,610.2 NGL sales—related parties 301.4 39.5 180.2 131.2 (652.3) — Crude oil and condensate sales—related parties — — — 1.5 (1.5) — Product sales—related parties 301.4 39.5 180.2 132.7 (653.8) — Gathering and transportation 12.8 16.3 44.6 39.0 — 112.7 Processing 7.5 0.9 26.5 27.0 — 61.9 NGL services — 16.9 — — — 16.9 Crude services 5.5 10.3 2.8 0.1 — 18.7 Other services 0.2 0.4 0.1 0.1 — 0.8 Midstream services 26.0 44.8 74.0 66.2 — 211.0 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 681.5 1,228.7 334.0 231.0 (654.0) 1,821.2 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (576.6) (1,110.8) (218.0) (149.4) 654.0 (1,400.8) Realized loss on derivatives (8.7) (14.9) (6.8) (2.0) — (32.4) Change in fair value of derivatives 10.2 (8.8) (2.3) (0.3) — (1.2) Adjusted gross margin 106.4 94.2 106.9 79.3 — 386.8 Operating expenses (37.3) (30.5) (19.8) (19.3) — (106.9) Segment profit 69.1 63.7 87.1 60.0 — 279.9 Depreciation and amortization (35.4) (34.6) (52.3) (28.5) (2.2) (153.0) Gain on disposition of assets 0.1 0.2 — 0.1 — 0.4 General and administrative — — — — (28.2) (28.2) Interest expense, net of interest income — — — — (60.1) (60.1) Loss from unconsolidated affiliates — — — — (2.3) (2.3) Income (loss) before non-controlling interest and income taxes $ 33.8 $ 29.3 $ 34.8 $ 31.6 $ (92.8) $ 36.7 Capital expenditures $ 25.8 $ 0.4 $ 10.3 $ 3.3 $ 0.6 $ 40.4 ____________________________ (1) Includes related party cost of sales of $4.9 million for the three months ended September 30, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million for the three months ended September 30, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended September 30, 2020 Natural gas sales $ 46.5 $ 76.4 $ 40.1 $ 16.0 $ — $ 179.0 NGL sales 0.1 402.3 1.2 — — 403.6 Crude oil and condensate sales 82.6 21.7 9.2 — — 113.5 Product sales 129.2 500.4 50.5 16.0 — 696.1 NGL sales—related parties 95.6 3.3 85.4 21.4 (205.7) — Crude oil and condensate sales—related parties — — — 0.7 (0.7) — Product sales—related parties 95.6 3.3 85.4 22.1 (206.4) — Gathering and transportation 17.9 10.7 56.7 43.4 — 128.7 Processing 8.0 0.3 32.4 33.3 — 74.0 NGL services — 14.2 — — — 14.2 Crude services 3.8 12.2 3.7 — — 19.7 Other services 0.2 0.4 0.1 0.2 — 0.9 Midstream services 29.9 37.8 92.9 76.9 — 237.5 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 254.7 541.5 228.9 115.0 (206.5) 933.6 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (185.4) (441.4) (101.0) (28.2) 206.5 (549.5) Realized loss on derivatives (0.4) (0.6) (1.7) (0.2) — (2.9) Change in fair value of derivatives 0.9 (2.7) (0.3) (0.1) — (2.2) Adjusted gross margin 69.8 96.8 125.9 86.5 — 379.0 Operating expenses (22.9) (31.1) (20.1) (20.2) — (94.3) Segment profit 46.9 65.7 105.8 66.3 — 284.7 Depreciation and amortization (31.9) (36.9) (53.0) (36.8) (1.7) (160.3) Gain on disposition of assets — — — 1.8 — 1.8 General and administrative — — — — (25.7) (25.7) Interest expense, net of interest income — — — — (55.5) (55.5) Loss from unconsolidated affiliates — — — — (0.2) (0.2) Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ 15.0 $ 28.8 $ 52.8 $ 31.3 $ (82.7) $ 45.2 Capital expenditures $ 28.5 $ 8.5 $ 2.6 $ 3.0 $ 0.6 $ 43.2 ____________________________ (1) Includes related party cost of sales of $2.0 million for the three months ended September 30, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $158.6 million for the three months ended September 30, 2020. Permian Louisiana Oklahoma North Texas Corporate Totals Nine Months Ended September 30, 2021 Natural gas sales $ 381.7 $ 426.4 $ 139.7 $ 109.4 $ — $ 1,057.2 NGL sales 0.9 2,231.2 1.3 1.0 — 2,234.4 Crude oil and condensate sales 472.1 154.5 50.5 — — 677.1 Product sales 854.7 2,812.1 191.5 110.4 — 3,968.7 NGL sales—related parties 661.8 93.3 430.4 306.4 (1,491.9) — Crude oil and condensate sales—related parties — — 0.1 5.1 (5.2) — Product sales—related parties 661.8 93.3 430.5 311.5 (1,497.1) — Gathering and transportation 34.3 48.5 141.8 117.6 — 342.2 Processing 21.7 1.9 70.5 81.1 — 175.2 NGL services — 56.0 — 0.2 — 56.2 Crude services 13.0 29.8 9.5 0.5 — 52.8 Other services 0.6 1.3 0.5 0.4 — 2.8 Midstream services 69.6 137.5 222.3 199.8 — 629.2 Crude services—related parties — — 0.2 — (0.2) — Other services—related parties — 2.4 — — (2.4) — Midstream services—related parties — 2.4 0.2 — (2.6) — Revenue from contracts with customers 1,586.1 3,045.3 844.5 621.7 (1,499.7) 4,597.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (1,304.5) (2,690.1) (533.9) (361.8) 1,499.7 (3,390.6) Realized loss on derivatives (69.8) (32.0) (15.7) (4.8) — (122.3) Change in fair value of derivatives (3.0) (18.6) (9.4) (1.9) — (32.9) Adjusted gross margin 208.8 304.6 285.5 253.2 — 1,052.1 Operating expenses (52.9) (91.4) (57.3) (58.4) — (260.0) Segment profit 155.9 213.2 228.2 194.8 — 792.1 Depreciation and amortization (103.5) (106.8) (153.6) (86.0) (6.0) (455.9) Gain on disposition of assets 0.2 0.3 — 0.2 — 0.7 General and administrative — — — — (80.3) (80.3) Interest expense, net of interest income — — — — (180.1) (180.1) Loss from unconsolidated affiliates — — — — (9.9) (9.9) Other income — — — — 0.1 0.1 Income (loss) before non-controlling interest and income taxes $ 52.6 $ 106.7 $ 74.6 $ 109.0 $ (276.2) $ 66.7 Capital expenditures $ 78.6 $ 5.4 $ 17.1 $ 7.6 $ 1.1 $ 109.8 ____________________________ (1) Includes related party cost of sales of $11.7 million for the nine months ended September 30, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million for the nine months ended September 30, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Nine Months Ended September 30, 2020 Natural gas sales $ 94.0 $ 226.6 $ 110.0 $ 50.7 $ — $ 481.3 NGL sales 0.2 1,056.9 2.9 0.3 — 1060.3 Crude oil and condensate sales 454.6 95.0 30.4 — — 580.0 Product sales 548.8 1,378.5 143.3 51.0 — 2,121.6 NGL sales—related parties 201.0 13.3 209.0 52.5 (475.8) — Crude oil and condensate sales—related parties 0.1 — (0.1) 2.6 (2.6) — Product sales—related parties 201.1 13.3 208.9 55.1 (478.4) — Gathering and transportation 47.3 33.9 165.5 133.5 — 380.2 Processing 19.8 1.6 97.8 101.7 — 220.9 NGL services — 52.4 — 0.1 — 52.5 Crude services 13.0 33.8 12.6 — — 59.4 Other services 1.0 1.2 0.3 0.7 — 3.2 Midstream services 81.1 122.9 276.2 236.0 — 716.2 Crude services—related parties — — 0.3 — (0.3) — Midstream services—related parties — — 0.3 — (0.3) — Revenue from contracts with customers 831.0 1,514.7 628.7 342.1 (478.7) 2,837.8 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (637.7) (1,213.6) (255.8) (74.1) 478.7 (1,702.5) Realized gain (loss) on derivatives (0.6) 1.9 (1.7) 0.1 — (0.3) Change in fair value of derivatives 2.3 (7.8) (2.4) (0.1) — (8.0) Adjusted gross margin 195.0 295.2 368.8 268.0 — 1,127.0 Operating expenses (71.1) (90.4) (62.4) (59.2) — (283.1) Segment profit 123.9 204.8 306.4 208.8 — 843.9 Depreciation and amortization (92.1) (109.3) (163.7) (110.4) (5.8) (481.3) Impairments (184.6) (169.9) — — — (354.5) Gain (loss) on disposition of assets (4.9) 0.1 0.1 1.9 — (2.8) General and administrative — — — — (79.6) (79.6) Interest expense, net of interest income — — — — (166.3) (166.3) Gain on extinguishment of debt — — — — 32.0 32.0 Income from unconsolidated affiliates — — — — 0.8 0.8 Other income — — — — 0.4 0.4 Income (loss) before non-controlling interest and income taxes $ (157.7) $ (74.3) $ 142.8 $ 100.3 $ (218.5) $ (207.4) Capital expenditures $ 161.4 $ 39.3 $ 14.1 $ 10.7 $ 1.7 $ 227.2 ____________________________
Schedule of Segment Assets	The table below represents information about segment assets as of September 30, 2021 and December 31, 2020 (in millions): Segment Identifiable Assets: September 30, 2021 December 31, 2020 Permian $ 2,391.2 $ 2,236.3 Louisiana 2,489.4 2,312.4 Oklahoma 2,661.5 2,847.6 North Texas 938.0 1,008.6 Corporate (1) 146.4 146.0 Total identifiable assets $ 8,626.5 $ 8,550.9 ____________________________

Other Information (Tables)

Other Information (Tables)	9 Months Ended
	Sep. 30, 2021
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: September 30, 2021 December 31, 2020 Natural gas and NGLs inventory $ 116.6 $ 44.9 Prepaid expenses and other 39.6 13.8 Other current assets $ 156.2 $ 58.7 Other current liabilities: September 30, 2021 December 31, 2020 Accrued interest $ 71.7 $ 35.7 Accrued wages and benefits, including taxes 26.0 22.5 Accrued ad valorem taxes 32.4 26.5 Capital expenditure accruals 15.0 10.6 Short-term lease liability 15.8 16.3 Operating expense accruals 11.7 8.4 Other 43.3 29.1 Other current liabilities $ 215.9 $ 149.1

General (Details)

General (Details) mi in Thousands, bbl in Thousands	9 Months Ended
	Sep. 30, 2021Bcf / dfractionatorprocessingPlantmibbl
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of miles of pipeline | mi	12
Number of natural gas processing plants | processingPlant	23
Amount of processing capacity | Bcf / d	5.5
Number of fractionators | fractionator	7
Capacity of fractionators per day, barrels | bbl	290

Significant Accounting Polici_3

Significant Accounting Policies - Narrative (Details) - Amarillo Rattler, LLC	Apr. 30, 2021USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash (including working capital payment)	$ 50,000,000
Installment payable	10,000,000
Business combination, maximum earnout	$ 15,000,000

Significant Accounting Polici_4

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Sep. 30, 2021USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 817.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 38.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 136.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 123.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 107.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 63.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 347.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period

Significant Accounting Polici_5

Significant Accounting Policies - Fair Value of Identified Assets Received and Liabilities Assumed (Details) - Amarillo Rattler, LLC $ in Millions	Apr. 30, 2021USD ($)
Consideration
Cash (including working capital payment)	$ 50.6
Installment payable	10
Contingent consideration fair value	6.9
Total consideration	67.5
Purchase price allocation
Cash acquired	1.3
Current assets (including $1.3 million in cash)	1.4
Property and equipment	16.3
Intangible assets	50.6
Other assets, net	0.6
Current liabilities	(0.8)
Other long-term liabilities	(0.6)
Total identifiable net assets	$ 67.5

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 31.9	$ 30.9	$ 94.4	$ 92.7
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			14 years 10 months 24 days

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance			$ 1,794.2
Accumulated Amortization, Beginning Balance			(668.8)
Net Carrying Amount, Beginning Balance			1,125.4
Customer relationships obtained from acquisition of business			50.6
Amortization expense	$ (31.9)	$ (30.9)	(94.4)	$ (92.7)
Gross Carrying Amount, Ending Balance	1,844.8		1,844.8
Accumulated Amortization, Ending Balance	(763.2)		(763.2)
Net Carrying Amount, Ending Balance	$ 1,081.6		$ 1,081.6

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
2021 (remaining)	$ 31.9
2022	127.6
2023	127.6
2024	127.6
2025	110.3
Thereafter	556.6
Total	$ 1,081.6	$ 1,125.4

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1],[2]	$ 1,400.8	$ 549.5	$ 3,390.6	$ 1,702.5
Accounts payable to related party		1.9		1.9		$ 1
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization		4.9	2	11.7	6.2
Accounts payable to related party		1.9		1.9		$ 1
GIP
Related Party Transaction [Line Items]
General and administrative expenses from transactions with related party		$ 0	$ 0.2	$ 0.2	$ 0.2
[1]	Includes related party cost of sales of $11.7 million and $6.2 million for the nine months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million and $475.5 million for the nine months ended September 30, 2021 and 2020, respectively.
[2]	Includes related party cost of sales of $4.9 million and $2.0 million for the three months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million and $158.6 million for the three months ended September 30, 2021 and 2020, respectively.

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Debt Instrument
Outstanding principal	$ 4,427.3	$ 4,632.3
Premium (discount)	(5.8)	(5.9)
Long-term debt	4,421.5	4,626.4
Debt issuance costs	(28.9)	(32.6)
Less: Current maturities of long-term debt	(150)	(349.8)
Long-term debt, net of unamortized issuance cost	4,242.6	4,244
Debt issuance cost accumulated amortization	17.5	14.1
Term Loan Due 2021
Debt Instrument
Outstanding principal	150	350
Premium (discount)	0	0
Long-term debt	$ 150	$ 350
Effective interest rate	1.60%	1.70%
Consolidated Credit Facility due 2024
Debt Instrument
Outstanding principal	$ 0	$ 0
Premium (discount)	0	0
Long-term debt	0	0
AR Facility due 2024
Debt Instrument
Outstanding principal	245	250
Premium (discount)	0	0
Long-term debt	$ 245	$ 250
Effective interest rate	1.20%	2.00%
4.4% Senior Notes Due 2024
Debt Instrument
Outstanding principal	$ 521.8	$ 521.8
Premium (discount)	0.8	1.1
Long-term debt	$ 522.6	522.9
Stated interest rate	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding principal	$ 720.8	720.8
Premium (discount)	(0.4)	(0.6)
Long-term debt	$ 720.4	720.2
Stated interest rate	4.15%
4.85 Senior Notes Due 2026
Debt Instrument
Outstanding principal	$ 491	491
Premium (discount)	(0.3)	(0.4)
Long-term debt	$ 490.7	490.6
Stated interest rate	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	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	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	5.60%
5.05 Senior Notes Due 2045
Debt Instrument
Outstanding principal	$ 450	450
Premium (discount)	(5.6)	(5.7)
Long-term debt	$ 444.4	444.3
Stated interest rate	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	5.45%

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Sep. 24, 2021USD ($)	Apr. 30, 2021USD ($)	Feb. 26, 2021USD ($)	Oct. 21, 2020USD ($)	Dec. 11, 2018USD ($)	Sep. 30, 2021USD ($)	May 31, 2021USD ($)	Sep. 30, 2021USD ($)	Dec. 31, 2020USD ($)
Debt Instrument
Increase (decrease) in accounts receivable								$ 708,100,000
Outstanding principal						$ 4,427,300,000		4,427,300,000	$ 4,632,300,000
Amarillo Rattler, LLC
Debt Instrument
Payments to acquire gathering and processing system		$ 50,000,000
Term Loan Due 2021
Debt Instrument
Line of credit facility, consolidated indebtedness to consolidated EBITDA, ratio					5.5
Outstanding principal						150,000,000		150,000,000	350,000,000
Letters of credit
Debt Instrument
Additional amount available (not to exceed)								1,750,000,000
Line of credit facility, fair value of amount outstanding						0		0
AR Facility due 2024
Debt Instrument
Outstanding principal						245,000,000		245,000,000	$ 250,000,000
Minimum | Term Loan Due 2021
Debt Instrument
Conditional Acquisition Purchase Price					$ 50,000,000
Maximum | Term Loan Due 2021
Debt Instrument
Line of credit facility, consolidated indebtedness to consolidated EBITDA, ratio					5.5
Letter of Credit | ENLC | Letters of credit
Debt Instrument
Line of credit facility, fair value of amount outstanding						41,100,000		41,100,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity	$ 350,000,000		$ 300,000,000	$ 250,000,000		350,000,000		$ 350,000,000
Line of credit facility, increase in period	$ 50,000,000		$ 50,000,000
Drawn fee percentage	1.10%		1.25%	1.625%				1.10%
Line of Credit | LIBOR | Minimum | Asset-backed Securities
Debt Instrument
Variable rate			0.00%	0.375%
Unsecured Debt | Term Loan Due 2021
Debt Instrument
Repayments of borrowings						100,000,000	$ 100,000,000
Face amount						$ 150,000,000		$ 150,000,000
Unsecured Debt | Letters of credit
Debt Instrument
Line of credit facility, consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio		5.5
Unsecured Debt | Minimum | Letters of credit
Debt Instrument
Conditional Acquisition Purchase Price								$ 50,000,000
Unsecured Debt | Maximum | Letters of credit
Debt Instrument
Line of credit facility, consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio						5.5		5.5
Letter of Credit | Letters of credit
Debt Instrument
Maximum borrowing capacity						$ 500,000,000		$ 500,000,000
Covenant, percentage of letter of credits guaranteed						105.00%		105.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.1)	$ (0.4)	$ (0.2)	$ (1.1)
Deferred income tax benefit (expense)	(4.3)	(5.6)	(12.2)	17.1
Income tax benefit (expense)	(4.4)	(6)	(12.4)	16
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit (expense) based on federal statutory rate	(2)	(3.6)	4.2	60
State income tax benefit (expense), net of federal benefit	(0.3)	(0.6)	0.5	6.4
Unit-based compensation	(0.2)	(1.6)	(3.1)	(6)
Non-deductible expense related to goodwill impairment	0	0	0	(43.4)
Change in valuation allowance	(1.6)	0	(3.8)	0
Oklahoma statutory rate change	0	0	(7.6)	0
Other	(0.3)	(0.2)	(2.6)	(1)
Income tax benefit (expense)	$ (4.4)	$ (6)	(12.4)	$ 16
Deferred state income tax expense (benefit)			$ 7.6

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ 124.2		$ 124.2		$ 108.6
Deferred tax assets	484.1		484.1		396
Deferred tax assets, valuation allowance	157.1		157.1		$ 153.3
Change in valuation allowance	$ 1.6	$ 0	$ 3.8	$ 0

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ in Millions	3 Months Ended								9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2021	Sep. 30, 2020
Series B Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)	151,626	151,248	150,871	150,494	150,119	149,745	149,371	148,999
Cash distributions	$ 17.1	$ 17	$ 17	$ 16.9	$ 16.9	$ 16.8	$ 16.8	$ 16.8
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)	60,650,397			60,197,784					60,650,397
Preferred units, outstanding (in shares)	60,650,397			60,197,784					60,650,397
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
Preferred units, outstanding (in shares)	400,000			400,000					400,000

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($)	3 Months Ended								9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2021	Sep. 30, 2020	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)	2,076,545								2,394,296
Payment for common unit repurchases	$ 12,500,000								$ 14,500,000	$ 0
Shares repurchased, average cost per share (in dollars per share)	$ 6.02								$ 6.05
Distributed earnings allocated to:
Total distributed earnings	$ 46,800,000				$ 46,600,000				$ 140,900,000	139,900,000
Undistributed loss allocated to:
Total undistributed loss, basic	(44,900,000)				(34,000,000)				(173,300,000)	(410,000,000)
Total undistributed loss, diluted	(44,900,000)				(34,000,000)				(173,300,000)	(410,000,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic	1,900,000				12,600,000				(32,400,000)	(270,100,000)
Total net income (loss), diluted	$ 1,900,000				$ 12,600,000				$ (32,400,000)	$ (270,100,000)
Basic and diluted total net income (loss) attributable to ENLC per unit:
Basic (in dollars per share)	$ 0				$ 0.03				$ (0.07)	$ (0.55)
Diluted (in dollars per share)	0				0.03				$ (0.07)	$ (0.55)
Distribution declared/unit (in dollars per share)	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.1875
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings	$ 1,000,000				$ 700,000				$ 3,200,000	$ 2,300,000
Undistributed loss allocated to:
Total undistributed loss, basic	(1,000,000)				(600,000)				(4,000,000)	(7,000,000)
Total undistributed loss, diluted	(1,000,000)				(600,000)				(4,000,000)	(7,000,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic	0				100,000				(800,000)	(4,700,000)
Total net income (loss), diluted	0				100,000				(800,000)	(4,700,000)
Common units
Distributed earnings allocated to:
Total distributed earnings	45,800,000				45,900,000				137,700,000	137,600,000
Undistributed loss allocated to:
Total undistributed loss, basic	(43,900,000)				(33,400,000)				(169,300,000)	(403,000,000)
Total undistributed loss, diluted	(43,900,000)				(33,400,000)				(169,300,000)	(403,000,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic	1,900,000				12,500,000				(31,600,000)	(265,400,000)
Total net income (loss), diluted	$ 1,900,000				$ 12,500,000				$ (31,600,000)	$ (265,400,000)

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Earnings Per Share [Abstract]
Weighted average basic common units outstanding (in units)	488.6	489.7	489.6	489.2
Dilutive effect of non-vested restricted units (in units)	6.2	1.2	0	0
Total weighted average diluted common units outstanding (in units)	494.8	490.9	489.6	489.2

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Equity method investments
Distributions	$ 0.1	$ 0	$ 3.8	$ 2
Income (loss) from unconsolidated affiliates	(2.3)	(0.2)	(9.9)	0.8
Total investment in unconsolidated affiliates	$ 29		$ 29		$ 41.6
GCF
Equity method investments
Ownership interest	38.75%		38.75%
Distributions	$ 0	0	$ 3.5	1.6
Income (loss) from unconsolidated affiliates	$ (1.7)	0.4	$ (8.1)	2.5
Cedar Cove JV
Equity method investments
Ownership interest	30.00%		30.00%
Distributions	$ 0.1	0	$ 0.3	0.4
Income (loss) from unconsolidated affiliates	(0.6)	$ (0.6)	(1.8)	$ (1.7)
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	27.9		27.9		41.6
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	29		29		40.6
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	$ (1.1)		$ (1.1)		$ 1

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Allocation
Total unit-based compensation expense	$ 6.4	$ 8.4	$ 19.3	$ 24.6
Amount of related income tax benefit recognized in net income (loss)	1.5	2	4.5	5.8
Unit-based compensation	0.2	1.6	3.1	6
Restricted units
Allocation
Unit-based compensation	0.2	1.6	3.1	6
Cost of unit-based compensation charged to operating expense
Allocation
Total unit-based compensation expense	1.5	2	4.9	6.2
Cost of unit-based compensation charged to general and administrative expense
Allocation
Total unit-based compensation expense	$ 4.9	$ 6.4	$ 14.4	$ 18.4

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended				3 Months Ended		9 Months Ended
	Jan. 31, 2021	Jul. 31, 2020	Mar. 31, 2020	Jan. 31, 2020	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Unvested restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)	5,350,086						5,350,086
Granted (in shares)							3,926,541
Vested (in shares)							(1,234,251)
Forfeited (in shares)							(478,554)
Non-vested, end of period (in shares)					7,563,822		7,563,822
Aggregate intrinsic value, end of period					$ 51.6		$ 51.6
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)	$ 8.45						$ 8.45
Granted (in dollars per share)							3.85
Vested (in dollars per share)							13.01
Forfeited (in dollars per share)							6.11
Non-vested, end of period (in dollars per share)					$ 5.47		$ 5.47
Incentive unit award vesting period							3 years
Units withheld for payroll taxes (in shares)							369,817
Aggregate intrinsic value of units vested					$ 1.5	$ 1	$ 5.4	$ 11.9
Fair value of units vested					3.6	$ 6	16.1	31
Unrecognized compensation cost related to non-vested restricted incentive units					$ 17.7		$ 17.7
Unrecognized compensation costs, weighted average period for recognition							1 year 7 months 6 days
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)	2,351,241						2,351,241
Granted (in shares)							1,388,139
Vested (in shares)							(164,553)
Non-vested, end of period (in shares)					3,574,827		3,574,827
Aggregate intrinsic value, end of period					$ 24.4		$ 24.4
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)	$ 8.82						$ 8.82
Granted (in dollars per share)							4.70
Vested (in dollars per share)							26.73
Non-vested, end of period (in dollars per share)					$ 6.40		$ 6.40
Units withheld for payroll taxes (in shares)							63,901
Aggregate intrinsic value of units vested							$ 0.6	0.9
Fair value of units vested							4.4	$ 5.5
Unrecognized compensation cost related to non-vested restricted incentive units					$ 9.7		$ 9.7
Unrecognized compensation costs, weighted average period for recognition							1 year 8 months 12 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)	4.70	$ 2.33	$ 1.13	$ 7.69
Beginning TSR Price (in dollars per share)	$ 3.71	$ 2.52	$ 1.25	$ 6.13
Risk-free interest rate	0.17%	0.17%	0.42%	1.62%
Volatility factor	71.00%	67.00%	51.00%	37.00%
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting							0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting							200.00%

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($)	1 Months Ended			3 Months Ended												9 Months Ended
	Sep. 30, 2021	May 31, 2021	Dec. 31, 2020	Sep. 30, 2021		Jun. 30, 2021		Mar. 31, 2021		Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Sep. 30, 2021		Sep. 30, 2020		Apr. 30, 2019
Derivatives
Derivative, notional amount	$ 150,000,000			$ 150,000,000												$ 150,000,000				$ 850,000,000
Derivative, fixed interest rate																				2.28%
Derivative, termination payment	500,000	$ 1,300,000	$ 10,900,000
Derivative, notional amount, amount terminated	100,000,000	$ 100,000,000	500,000,000	100,000,000												100,000,000				$ 700,000,000
Derivative liability	12,700,000			12,700,000												12,700,000
Change in fair value of derivatives due to accelerated amortization				3,500,000												9,500,000
Tax benefit (expense)				(1,200,000)	[1]	$ (1,100,000)		$ (1,100,000)		$ (1,100,000)		$ (500,000)		$ 4,000,000		(3,400,000)		$ 2,400,000
Unrealized gain (loss) on designated cash flow hedge				3,800,000	[1],[2]	$ 3,700,000	[3]	$ 3,600,000	[4]	3,600,000	[1],[5]	$ 1,500,000	[6]	$ (13,100,000)	[7]	11,100,000	[1]	(8,000,000)	[1]
Interest expense				5,000,000						4,600,000						14,600,000		9,600,000
Interest expense expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	3,700,000			3,700,000												3,700,000
Fair value of derivative liabilities—current	(110,900,000)		(37,100,000)	(110,900,000)												(110,900,000)
Interest rate swaps
Derivatives
Change in fair value of interest rate swaps				5,000,000						4,700,000						14,500,000		(10,400,000)
Tax benefit (expense)				(1,200,000)						(1,100,000)						(3,400,000)		2,400,000
Unrealized gain (loss) on designated cash flow hedge				3,800,000						$ 3,600,000						11,100,000		$ (8,000,000)
Fair value of derivative liabilities—current	$ (700,000)		$ (7,600,000)	$ (700,000)												$ (700,000)
[1]	Includes a tax expense of $1.2 million and a tax expense of $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and a tax expense of $3.4 million and a tax benefit of $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.
[2]	Includes a tax expense of $1.2 million.
[3]	Includes a tax expense of $1.1 million.
[4]	Includes a tax expense of $1.1 million.
[5]	Includes a tax expense of $1.1 million.
[6]	Includes a tax expense of $0.5 million.
[7]	Includes a tax benefit of $4.0 million.

Derivatives - Components of Com

Derivatives - Components of Commodity Swap Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivatives
Change in fair value of derivatives	$ (1.2)	$ (2.2)	$ (32.9)	$ (8)
Realized gain (loss) on derivatives			(37.5)	(7.3)
Loss on derivative activity	(33.6)	(5.1)	(155.2)	(8.3)
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	(1.2)	(2.2)	(32.9)	(8)
Realized gain (loss) on derivatives	(32.4)	(2.9)	(122.3)	(0.3)
Loss on derivative activity	$ (33.6)	$ (5.1)	$ (155.2)	$ (8.3)

Derivatives - Fair Value of Com

Derivatives - Fair Value of Commodity Swap Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivatives
Fair value of derivative assets—current	$ 75.3	$ 25
Fair value of derivative assets—long-term	2.2	4.9
Fair value of derivative liabilities—current	(110.9)	(37.1)
Fair value of derivative liabilities—long-term	(2.3)	(2.5)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	75.3	25
Fair value of derivative assets—long-term	2.2	4.9
Fair value of derivative liabilities—current	(110.2)	(29.5)
Fair value of derivative liabilities—long-term	(2.3)	(2.5)
Net fair value of commodity swaps	$ (35)	$ (2.1)

Derivatives - Commodity Swaps A

Derivatives - Commodity Swaps Additional Information (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions	9 Months Ended
	Sep. 30, 2021USD ($)MMBTUgalMMBbls	Dec. 31, 2020USD ($)
Derivatives
Net Fair Value	$ (35,000,000)	$ (2,100,000)
Commodity
Derivatives
Net Fair Value	(35,000,000)
Maximum loss if counterparties fail to perform	77,500,000
Possible reduction in maximum loss if counterparties fail to perform	$ 0
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	169.3
Net Fair Value	$ (56,300,000)
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	7.8
Net Fair Value	$ 1,400,000
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	9.8
Net Fair Value	$ (17,600,000)
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	14.2
Net Fair Value	$ 25,000,000
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	7.8
Net Fair Value	$ (32,700,000)
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	3.8
Net Fair Value	$ 45,200,000

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - Level 2 - Recurring - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Interest rate swaps
Fair Value
Net Fair Value	$ (0.7)	$ (7.6)
Commodity swaps
Fair Value
Net Fair Value	$ (35)	$ (2.1)

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Sep. 30, 2021	Apr. 30, 2021	Dec. 31, 2020
Fair Value
Debt issuance costs	$ 28,900,000		$ 32,600,000
Amarillo Rattler, LLC
Fair Value
Installment payable		$ 10,000,000
Business combination, maximum earnout		$ 15,000,000
Carrying Value
Fair Value
Long-term debt	4,392,600,000		4,593,800,000
Installment payable	10,000,000		0
Contingent consideration fair value	6,900,000		0
Fair Value
Fair Value
Long-term debt	4,466,700,000		4,318,200,000
Installment payable	10,000,000		0
Contingent consideration fair value	$ 6,900,000		$ 0

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting
Revenue from contracts with customers		$ 1,821.2	$ 933.6	$ 4,597.9	$ 2,837.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1],[2]	(1,400.8)	(549.5)	(3,390.6)	(1,702.5)
Realized gain (loss) on derivatives		(32.4)	(2.9)	(122.3)	(0.3)
Change in fair value of derivatives		(1.2)	(2.2)	(32.9)	(8)
Adjusted gross margin		386.8	379	1,052.1	1,127
Operating expenses		(106.9)	(94.3)	(260)	(283.1)
Segment profit		279.9	284.7	792.1	843.9
Depreciation and amortization		(153)	(160.3)	(455.9)	(481.3)
Impairments		0	0	0	(354.5)
Gain on disposition of assets		0.4	1.8	0.7	(2.8)
General and administrative		(28.2)	(25.7)	(80.3)	(79.6)
Interest expense, net of interest income		(60.1)	(55.5)	(180.1)	(166.3)
Gain on extinguishment of debt		0	0	0	32
Income (loss) from unconsolidated affiliates		(2.3)	(0.2)	(9.9)	0.8
Other income		0	0.4	0.1	0.4
Income (loss) before non-controlling interest and income taxes		36.7	45.2	66.7	(207.4)
Capital expenditures		40.4	43.2	109.8	227.2
Related parties amount in cost of sales		4.9	2	11.7	6.2
Other depreciation and amortization		150.8	158.6	449.9	475.5
Permian
Segment Reporting
Revenue from contracts with customers		681.5	254.7	1,586.1	831
Cost of sales, exclusive of operating expenses and depreciation and amortization		(576.6)	(185.4)	(1,304.5)	(637.7)
Realized gain (loss) on derivatives		(8.7)	(0.4)	(69.8)	(0.6)
Change in fair value of derivatives		10.2	0.9	(3)	2.3
Adjusted gross margin		106.4	69.8	208.8	195
Operating expenses		(37.3)	(22.9)	(52.9)	(71.1)
Segment profit		69.1	46.9	155.9	123.9
Depreciation and amortization		(35.4)	(31.9)	(103.5)	(92.1)
Impairments					(184.6)
Gain on disposition of assets		0.1	0	0.2	(4.9)
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt					0
Income (loss) from unconsolidated affiliates		0	0	0	0
Other income			0	0	0
Income (loss) before non-controlling interest and income taxes		33.8	15	52.6	(157.7)
Capital expenditures		25.8	28.5	78.6	161.4
Louisiana
Segment Reporting
Revenue from contracts with customers		1,228.7	541.5	3,045.3	1,514.7
Cost of sales, exclusive of operating expenses and depreciation and amortization		(1,110.8)	(441.4)	(2,690.1)	(1,213.6)
Realized gain (loss) on derivatives		(14.9)	(0.6)	(32)	1.9
Change in fair value of derivatives		(8.8)	(2.7)	(18.6)	(7.8)
Adjusted gross margin		94.2	96.8	304.6	295.2
Operating expenses		(30.5)	(31.1)	(91.4)	(90.4)
Segment profit		63.7	65.7	213.2	204.8
Depreciation and amortization		(34.6)	(36.9)	(106.8)	(109.3)
Impairments					(169.9)
Gain on disposition of assets		0.2	0	0.3	0.1
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt					0
Income (loss) from unconsolidated affiliates		0	0	0	0
Other income			0	0	0
Income (loss) before non-controlling interest and income taxes		29.3	28.8	106.7	(74.3)
Capital expenditures		0.4	8.5	5.4	39.3
Oklahoma
Segment Reporting
Revenue from contracts with customers		334	228.9	844.5	628.7
Cost of sales, exclusive of operating expenses and depreciation and amortization		(218)	(101)	(533.9)	(255.8)
Realized gain (loss) on derivatives		(6.8)	(1.7)	(15.7)	(1.7)
Change in fair value of derivatives		(2.3)	(0.3)	(9.4)	(2.4)
Adjusted gross margin		106.9	125.9	285.5	368.8
Operating expenses		(19.8)	(20.1)	(57.3)	(62.4)
Segment profit		87.1	105.8	228.2	306.4
Depreciation and amortization		(52.3)	(53)	(153.6)	(163.7)
Impairments					0
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
Gain on extinguishment of debt					0
Income (loss) from unconsolidated affiliates		0	0	0	0
Other income			0	0	0
Income (loss) before non-controlling interest and income taxes		34.8	52.8	74.6	142.8
Capital expenditures		10.3	2.6	17.1	14.1
North Texas
Segment Reporting
Revenue from contracts with customers		231	115	621.7	342.1
Cost of sales, exclusive of operating expenses and depreciation and amortization		(149.4)	(28.2)	(361.8)	(74.1)
Realized gain (loss) on derivatives		(2)	(0.2)	(4.8)	0.1
Change in fair value of derivatives		(0.3)	(0.1)	(1.9)	(0.1)
Adjusted gross margin		79.3	86.5	253.2	268
Operating expenses		(19.3)	(20.2)	(58.4)	(59.2)
Segment profit		60	66.3	194.8	208.8
Depreciation and amortization		(28.5)	(36.8)	(86)	(110.4)
Impairments					0
Gain on disposition of assets		0.1	1.8	0.2	1.9
General and administrative		0	0	0	0
Interest expense, net of interest income		0	0	0	0
Gain on extinguishment of debt					0
Income (loss) from unconsolidated affiliates		0	0	0	0
Other income			0	0	0
Income (loss) before non-controlling interest and income taxes		31.6	31.3	109	100.3
Capital expenditures		3.3	3	7.6	10.7
Corporate
Segment Reporting
Revenue from contracts with customers		(654)	(206.5)	(1,499.7)	(478.7)
Cost of sales, exclusive of operating expenses and depreciation and amortization		654	206.5	1,499.7	478.7
Realized gain (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		(2.2)	(1.7)	(6)	(5.8)
Impairments					0
Gain on disposition of assets		0	0	0	0
General and administrative		(28.2)	(25.7)	(80.3)	(79.6)
Interest expense, net of interest income		(60.1)	(55.5)	(180.1)	(166.3)
Gain on extinguishment of debt					32
Income (loss) from unconsolidated affiliates		(2.3)	(0.2)	(9.9)	0.8
Other income			0.4	0.1	0.4
Income (loss) before non-controlling interest and income taxes		(92.8)	(82.7)	(276.2)	(218.5)
Capital expenditures		0.6	0.6	1.1	1.7
Product sales
Segment Reporting
Revenue from contracts with customers		1,610.2	696.1	3,968.7	2,121.6
Product sales | Permian
Segment Reporting
Revenue from contracts with customers		354.1	129.2	854.7	548.8
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers		1,144.3	500.4	2,812.1	1,378.5
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		79.7	50.5	191.5	143.3
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers		32.1	16	110.4	51
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		432.9	179	1,057.2	481.3
Product sales, Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers		159.3	46.5	381.7	94
Product sales, Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers		183.2	76.4	426.4	226.6
Product sales, Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		58.2	40.1	139.7	110
Product sales, Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers		32.2	16	109.4	50.7
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		899.2	403.6	2,234.4	1,060.3
Product sales, NGL sales | Permian
Segment Reporting
Revenue from contracts with customers		0.4	0.1	0.9	0.2
Product sales, NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers		898.6	402.3	2,231.2	1,056.9
Product sales, NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.3	1.2	1.3	2.9
Product sales, NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers		(0.1)	0	1	0.3
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		278.1	113.5	677.1	580
Product sales, Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers		194.4	82.6	472.1	454.6
Product sales, Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers		62.5	21.7	154.5	95
Product sales, Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers		21.2	9.2	50.5	30.4
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		301.4	95.6	661.8	201.1
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		39.5	3.3	93.3	13.3
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		180.2	85.4	430.5	208.9
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		132.7	22.1	311.5	55.1
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(653.8)	(206.4)	(1,497.1)	(478.4)
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		301.4	95.6	661.8	201
Product sales, NGL sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		39.5	3.3	93.3	13.3
Product sales, NGL sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		180.2	85.4	430.4	209
Product sales, NGL sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers		131.2	21.4	306.4	52.5
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(652.3)	(205.7)	(1,491.9)	(475.8)
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	0.1
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	0.1	(0.1)
Product sales, Crude oil and condensate sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers		1.5	0.7	5.1	2.6
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(1.5)	(0.7)	(5.2)	(2.6)
Midstream services
Segment Reporting
Revenue from contracts with customers		211	237.5	629.2	716.2
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers		26	29.9	69.6	81.1
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers		44.8	37.8	137.5	122.9
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers		74	92.9	222.3	276.2
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers		66.2	76.9	199.8	236
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		112.7	128.7	342.2	380.2
Midstream services, Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers		12.8	17.9	34.3	47.3
Midstream services, Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers		16.3	10.7	48.5	33.9
Midstream services, Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers		44.6	56.7	141.8	165.5
Midstream services, Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers		39	43.4	117.6	133.5
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		61.9	74	175.2	220.9
Midstream services, Processing | Permian
Segment Reporting
Revenue from contracts with customers		7.5	8	21.7	19.8
Midstream services, Processing | Louisiana
Segment Reporting
Revenue from contracts with customers		0.9	0.3	1.9	1.6
Midstream services, Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers		26.5	32.4	70.5	97.8
Midstream services, Processing | North Texas
Segment Reporting
Revenue from contracts with customers		27	33.3	81.1	101.7
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		16.9	14.2	56.2	52.5
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		16.9	14.2	56	52.4
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	0	0.2	0.1
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		18.7	19.7	52.8	59.4
Midstream services, Crude services | Permian
Segment Reporting
Revenue from contracts with customers		5.5	3.8	13	13
Midstream services, Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers		10.3	12.2	29.8	33.8
Midstream services, Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers		2.8	3.7	9.5	12.6
Midstream services, Crude services | North Texas
Segment Reporting
Revenue from contracts with customers		0.1	0	0.5	0
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		0.8	0.9	2.8	3.2
Midstream services, Other services | Permian
Segment Reporting
Revenue from contracts with customers		0.2	0.2	0.6	1
Midstream services, Other services | Louisiana
Segment Reporting
Revenue from contracts with customers		0.4	0.4	1.3	1.2
Midstream services, Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1	0.1	0.5	0.3
Midstream services, Other services | North Texas
Segment Reporting
Revenue from contracts with customers		0.1	0.2	0.4	0.7
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	0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers		0.1	0	2.4	0
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1	0.1	0.2	0.3
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(0.2)	(0.1)	(2.6)	(0.3)
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Crude services, related party | Permian
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Crude services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Crude services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers		0.1	0.1	0.2	0.3
Midstream services, Crude services, related party | North Texas
Segment Reporting
Revenue from contracts with customers		0	0	0	0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(0.1)	$ (0.1)	(0.2)	$ (0.3)
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		2.4
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)		$ (2.4)
[1]	Includes related party cost of sales of $11.7 million and $6.2 million for the nine months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million and $475.5 million for the nine months ended September 30, 2021 and 2020, respectively.
[2]	Includes related party cost of sales of $4.9 million and $2.0 million for the three months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million and $158.6 million for the three months ended September 30, 2021 and 2020, respectively.

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Segment Reporting
Total identifiable assets	$ 8,626.5	$ 8,550.9
Permian
Segment Reporting
Total identifiable assets	2,391.2	2,236.3
Louisiana
Segment Reporting
Total identifiable assets	2,489.4	2,312.4
Oklahoma
Segment Reporting
Total identifiable assets	2,661.5	2,847.6
North Texas
Segment Reporting
Total identifiable assets	938	1,008.6
Corporate
Segment Reporting
Total identifiable assets	$ 146.4	$ 146

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Other current assets:
Natural gas and NGLs inventory	$ 116.6	$ 44.9
Prepaid expenses and other	39.6	13.8
Other current assets	156.2	58.7
Other current liabilities:
Accrued interest	71.7	35.7
Accrued wages and benefits, including taxes	26	22.5
Accrued ad valorem taxes	32.4	26.5
Capital expenditure accruals	15	10.6
Short-term lease liability	15.8	16.3
Operating expense accruals	11.7	8.4
Other	43.3	29.1
Other current liabilities	$ 215.9	$ 149.1