EnLink Midstream (ENLC) 10-Q 5 May 21 2021 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Mar. 31, 2021	Apr. 29, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 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)		490,055,937
Document Fiscal Period Focus	Q1
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	Mar. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 72.8	$ 39.6
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.5, respectively	65.4	80.6
Accrued revenue and other	481.4	447.5
Fair value of derivative assets	40.2	25
Other current assets	65.6	58.7
Total current assets	725.4	651.4
Property and equipment, net of accumulated depreciation of $3,981.4 and $3,863.0, respectively	6,551.2	6,652.1
Intangible assets, net of accumulated amortization of $699.7 and $668.8, respectively	1,094.5	1,125.4
Investment in unconsolidated affiliates	31.7	41.6
Fair value of derivative assets	3.4	4.9
Other assets, net	110.1	75.5
Total assets	8,516.3	8,550.9
Current liabilities:
Accounts payable and drafts payable	58.7	60.5
Accounts payable to related party	1.2	1
Accrued gas, NGLs, condensate, and crude oil purchases	363.1	290.5
Fair value of derivative liabilities	59.3	37.1
Current maturities of long-term debt	349.8	349.8
Other current liabilities	165.9	149.1
Total current liabilities	998	888
Long-term debt	4,145.2	4,244
Asset retirement obligations	14.4	14.2
Other long-term liabilities	85.3	80.6
Deferred tax liability, net	111	108.6
Fair value of derivative liabilities	0	2.5
Members’ equity:
Members’ equity (490,055,402 and 489,381,149 units issued and outstanding, respectively)	1,454.2	1,508.8
Accumulated other comprehensive loss	(11.7)	(15.3)
Non-controlling interest	1,719.9	1,719.5
Total members’ equity	3,162.4	3,213
Commitments and contingencies
Total liabilities and members’ equity	$ 8,516.3	$ 8,550.9

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
ASSETS
Allowance for bad debt	$ 0.3	$ 0.5
Property and equipment, accumulated depreciation	3,981.4	3,863
Intangible assets, accumulated amortization	$ 699.7	$ 668.8
Members’ equity:
Common units issued (in shares)	490,055,402	489,381,149
Common units outstanding (in shares)	489,381,149	490,055,402

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Revenues:
Revenue from contracts with customers	$ 1,331.8	$ 1,136.9
Gain (loss) on derivative activity	(83.4)	19.2
Total revenues	1,248.4	1,156.1
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	934.7	755.3
Operating expenses	56.3	100.7
Depreciation and amortization	151	162.8
Impairments	0	353
Gain on disposition of assets	0	(0.6)
General and administrative	26	30.4
Total operating costs and expenses	1,168	1,401.6
Operating income (loss)	80.4	(245.5)
Other income (expense):
Interest expense, net of interest income	(60)	(55.6)
Gain on extinguishment of debt	0	5.3
Income (loss) from unconsolidated affiliates	(6.3)	1.7
Other expense	(0.1)	0
Total other expense	(66.4)	(48.6)
Income (loss) before non-controlling interest and income taxes	14	(294.1)
Income tax benefit (expense)	(1.4)	33.7
Net income (loss)	12.6	(260.4)
Net income attributable to non-controlling interest	25.3	26.4
Net loss attributable to ENLC	$ (12.7)	$ (286.8)
Net loss attributable to ENLC per unit:
Basic common unit (in dollars per share)	$ (0.03)	$ (0.59)
Diluted common unit (in dollars per share)	$ (0.03)	$ (0.59)
Product sales
Revenues:
Revenue from contracts with customers	$ 1,122.9	$ 892.9
Midstream services
Revenues:
Revenue from contracts with customers	$ 208.9	$ 244

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Income Statement [Abstract]
Related party cost of sales	$ 3.2	$ 2.9
Depreciation and amortization	151	162.8
Other Segments
Depreciation and amortization	$ 149	$ 160.8

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 12.6	$ (260.4)
Gain (loss) on designated cash flow hedge	[1],[2]	3.6	(13.1)
Comprehensive income (loss)		16.2	(273.5)
Comprehensive income attributable to non-controlling interest		25.3	26.4
Comprehensive loss attributable to ENLC		$ (9.1)	$ (299.9)
[1]	Includes a tax expense of $1.1 million and a tax benefit of $4.0 million for the three months ended March 31, 2021 and 2020, respectively.
[2]	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
	Mar. 31, 2021		Mar. 31, 2020
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ 1.1	[1]	$ (4)
[1]	Includes a tax expense of $1.1 million and a tax benefit of $4.0 million for the three months ended March 31, 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)
Gain (loss) on designated cash flow hedge	[2]	(13.1)	[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, 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)
Gain (loss) on designated cash flow hedge	[2]	3.6	[1]		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		490,055,402		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
[1]	Includes a tax expense of $1.1 million and a tax benefit of $4.0 million for the three months ended March 31, 2021 and 2020, respectively.
[2]	Includes a tax expense of $1.1 million.

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021		Mar. 31, 2020
Statement of Stockholders' Equity [Abstract]
Income tax (benefit) expense	$ 1.1	[1]	$ (4)
[1]	Includes a tax expense of $1.1 million and a tax benefit of $4.0 million for the three months ended March 31, 2021 and 2020, respectively.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ 12.6	$ (260.4)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	0	353
Depreciation and amortization	151	162.8
Utility credits	(40.4)	0
Deferred income tax (benefit) expense	1.3	(34)
Non-cash unit-based compensation	6.5	8.8
Non-cash (gain) loss on derivatives recognized in net income (loss)	7.8	(18)
Gain on extinguishment of debt	0	(5.3)
Amortization of debt issue costs, net discount (premium) of notes	1.2	1
Distribution of earnings from unconsolidated affiliates	0	1.6
(Income) loss from unconsolidated affiliates	6.3	(1.7)
Other operating activities	1.4	(1.2)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(18.7)	124.8
Natural gas and NGLs inventory, prepaid expenses, and other	1.2	44.5
Accounts payable, accrued product purchases, and other accrued liabilities	95.6	(193.9)
Net cash provided by operating activities	225.8	182
Cash flows from investing activities:
Additions to property and equipment	(23.5)	(112)
Distribution from unconsolidated affiliates in excess of earnings	3.6	0.2
Other investing activities	0.7	(3.7)
Net cash used in investing activities	(19.2)	(115.5)
Cash flows from financing activities:
Proceeds from borrowings	200	440
Payments on borrowings	(300)	(241)
Conversion of restricted units, net of units withheld for taxes	(1.2)	(4)
Distribution to members	(47.1)	(93.3)
Distributions to non-controlling interests	(26)	(24.7)
Contributions by non-controlling interests	0.9	37.1
Other financing activities	0	0.1
Net cash provided by (used in) financing activities	(173.4)	114.2
Net increase in cash and cash equivalents	33.2	180.7
Cash and cash equivalents, beginning of period	39.6	77.4
Cash and cash equivalents, end of period	72.8	258.1
Supplemental disclosures of cash flow information:
Cash paid for interest	17.2	22.3
Non-cash investing activities:
Non-cash accrual of property and equipment	(2.7)	2.8
Right-of-use assets obtained in exchange for operating lease liabilities	10.2	4.8
Non-cash financing activities:
Fair value adjustment related to redeemable non-controlling interest	$ 0	$ (4)

General

General	3 Months Ended
	Mar. 31, 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 11,900 miles of pipelines, 22 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 is considerable uncertainty regarding how long the COVID-19 pandemic will persist and affect economic conditions and the extent and duration of changes in consumer behavior.

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 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 Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue. For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue. The following table summarizes the contractually committed fees 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. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three months ended March 31, 2021, we had contractual commitments of $13.5 million under our MVC contracts and recorded $0.3 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2021 (remaining) $ 106.3 2022 127.5 2023 116.5 2024 104.4 2025 62.0 Thereafter 342.1 Total $ 858.8 ____________________________ (1) Amounts do not represent expected shortfall under these commitments.

Intangible Assets

Intangible Assets	3 Months Ended
	Mar. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and 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 range from 10 to 20 years. The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Three Months Ended March 31, 2021 Customer relationships, beginning of period $ 1,794.2 $ (668.8) $ 1,125.4 Amortization expense — (30.9) (30.9) Customer relationships, end of period $ 1,794.2 $ (699.7) $ 1,094.5 The weighted average amortization period for intangible assets is 15.0 years. Amortization expense was $30.9 million for each of the three months ended March 31, 2021 and 2020, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2021 (remaining) $ 92.5 2022 123.4 2023 123.4 2024 123.4 2025 106.1 Thereafter 525.7 Total $ 1,094.5

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2021
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions Transactions with Cedar Cove JV. For the three months ended March 31, 2021 and 2020, we recorded cost of sales of $3.2 million and $2.9 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 $1.2 million and $1.0 million at March 31, 2021 and December 31, 2020, respectively. Transactions with GIP . For the three months ended March 31, 2021, we recorded general and administrative expenses of $0.1 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 March 31, 2020.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	(5) Long-Term Debt As of March 31, 2021 and December 31, 2020, long-term debt consisted of the following (in millions): March 31, 2021 December 31, 2020 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Term Loan due 2021 (1) $ 350.0 $ — $ 350.0 $ 350.0 $ — $ 350.0 AR Facility due 2023 (2) 150.0 — 150.0 250.0 — 250.0 Consolidated Credit Facility due 2024 — — — — — — ENLK’s 4.40% Senior unsecured notes due 2024 521.8 1.0 522.8 521.8 1.1 522.9 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.5) 720.3 720.8 (0.6) 720.2 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.4) 490.6 491.0 (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 $ 4,532.3 $ (5.8) 4,526.5 $ 4,632.3 $ (5.9) 4,626.4 Debt issuance cost (3) (31.5) (32.6) Less: Current maturities of long-term debt (1) (349.8) (349.8) Long-term debt, net of unamortized issuance cost $ 4,145.2 $ 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 March 31, 2021 and December 31, 2020, respectively. The Term Loan will mature on December 10, 2021. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of March 31, 2021 and December 31, 2020, respectively. (2) Bears interest based on LIMR and/or LIBOR plus an applicable margin. The effective interest rate was 1.4% and 2.0% at March 31, 2021 and December 31, 2020, respectively. (3) Net of amortization of $15.3 million and $14.1 million at March 31, 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. The outstanding balance of the Term Loan was $350.0 million as of March 31, 2021. The obligations under the Term Loan are unsecured. At March 31, 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. 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 have 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 an 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 currently effective drawn fee to 1.25% rather than the previous 1.625%. 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 $505.9 million and long-term debt of $150.0 million as of March 31, 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 March 31, 2021, the AR Facility had a borrowing base of $262.1 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 1.25% at March 31, 2021. The drawn fee varies based on ENLC’s credit rating, and 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 October 20, 2023, unless extended in accordance with its terms or earlier terminated, 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 March 31, 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. 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 $27.5 million outstanding letters of credit as of March 31, 2021. At March 31, 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.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 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 2021 2020 Current income tax expense $ (0.1) $ (0.3) Deferred income tax benefit (expense) (1.3) 34.0 Income tax benefit (expense) $ (1.4) $ 33.7 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 2021 2020 Expected income tax benefit based on federal statutory rate $ 2.4 $ 67.3 State income tax benefit, net of federal benefit 0.2 8.0 Unit-based compensation (1) (2.5) 2.4 Non-deductible expense related to goodwill impairment — (43.4) Change in valuation allowance (1.2) — Other (0.3) (0.6) Income tax benefit (expense) $ (1.4) $ 33.7 ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of restricted incentive units. Deferred Tax Assets and Liabilities Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The deferred tax liabilities, net of deferred tax assets, are included in “Deferred tax liability, net” in the consolidated balance sheets. As of March 31, 2021, we had $111.0 million of deferred tax liabilities, net of $404.5 million of deferred tax assets, which included a $154.5 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.

Certain Provisions of the ENLK

Certain Provisions of the ENLK Partnership Agreement	3 Months Ended
	Mar. 31, 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 March 31, 2021 and December 31, 2020, there were 60,348,278 and 60,197,784 Series B Preferred Units issued and outstanding, respectively. A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 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 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 b. Series C Preferred Units As of March 31, 2021 and December 31, 2020, there were 400,000 Series C Preferred Units issued and outstanding, respectively. There was no distribution activity related to the Series C Preferred Units during the three months ended March 31, 2021 and 2020.

Members' Equity

Members' Equity	3 Months Ended
	Mar. 31, 2021
Earnings Per Share [Abstract]
Members' Equity	(8) Members’ Equity a. 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 2021 2020 Distributed earnings allocated to: Common units (1) $ 45.9 $ 45.8 Unvested restricted units (1) 1.1 0.8 Total distributed earnings $ 47.0 $ 46.6 Undistributed loss allocated to: Common units $ (58.3) $ (327.4) Unvested restricted units (1.4) (6.0) Total undistributed loss $ (59.7) $ (333.4) Net loss allocated to: Common units $ (12.4) $ (281.6) Unvested restricted units (0.3) (5.2) Total net loss $ (12.7) $ (286.8) Basic and diluted total net loss per unit: Basic $ (0.03) $ (0.59) Diluted $ (0.03) $ (0.59) ____________________________ (1) Represents distribution activity consistent with the distribution activity in “ Distributions ” below. There were 490.0 million and 488.7 million weighted average common units outstanding for the three months ended March 31, 2021 and 2020, respectively. All common unit equivalents were antidilutive because 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. b. Distributions A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 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 2020 Fourth Quarter of 2019 $ 0.1875 February 13, 2020 First Quarter of 2020 $ 0.09375 May 13, 2020

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(9) Investment in Unconsolidated Affiliates As of March 31, 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 2021 2020 GCF Distributions $ 3.5 $ 1.6 Equity in income (loss) $ (5.7) $ 1.8 Cedar Cove JV Distributions $ 0.1 $ 0.2 Equity in loss $ (0.6) $ (0.1) Total Distributions $ 3.6 $ 1.8 Equity in income (loss) $ (6.3) $ 1.7 The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2021 and December 31, 2020 (in millions): March 31, 2021 December 31, 2020 GCF $ 31.4 $ 40.6 Cedar Cove JV 0.3 1.0 Total investment in unconsolidated affiliates $ 31.7 $ 41.6

Employee Incentive Plans

Employee Incentive Plans	3 Months Ended
	Mar. 31, 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 2021 2020 Cost of unit-based compensation charged to operating expense $ 1.7 $ 2.2 Cost of unit-based compensation charged to general and administrative expense 4.8 6.6 Total unit-based compensation expense $ 6.5 $ 8.8 Amount of related income tax benefit recognized in net income (loss) (1) $ 1.5 $ 2.1 ____________________________ (1) For the three months ended March 31, 2021, the amount of related income tax benefit recognized in net income excluded $2.5 million of income tax expense related to book-to-tax differences recorded upon vesting of restricted units. For the three months ended March 31, 2020, the amount of related income tax benefit recognized in net loss excluded $2.4 million of income tax benefit related to book-to-tax differences recorded upon 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 three months ended March 31, 2021 is provided below: Three 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) 3,622,698 3.72 Vested (1)(2) (813,686) 12.52 Forfeited (116,444) 6.62 Non-vested, end of period 8,042,654 $ 5.93 Aggregate intrinsic value, end of period (in millions) $ 34.5 ____________________________ (1) Restricted incentive units typically vest at the end of three years. (2) Vested units included 240,085 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2021 and 2020 is provided below (in millions): Three Months Ended ENLC Restricted Incentive Units: 2021 2020 Aggregate intrinsic value of units vested $ 3.0 $ 10.1 Fair value of units vested $ 10.2 $ 18.9 As of March 31, 2021, there were $26.6 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 1.9 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: Three 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) $ 15.3 ____________________________ (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 three months ended March 31, 2021 and 2020 is provided below (in millions). Three Months Ended ENLC Performance Units: 2021 2020 Aggregate intrinsic value of units vested $ 0.6 $ 0.9 Fair value of units vested $ 4.4 $ 5.0 As of March 31, 2021, there were $14.9 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 1.8 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	3 Months Ended
	Mar. 31, 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 December 2020, in connection with the partial repayment of the Term Loan, we paid $10.9 million to terminate $500.0 million of the $850.0 million interest rate swaps and settled the outstanding derivative liability of $10.9 million. The unrealized loss remains in accumulated other comprehensive 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 months ended March 31, 2021, we amortized $2.9 million into interest expense out of accumulated other comprehensive income (loss) related to the termination of the interest rate swaps. The remaining $350.0 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 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 2021 2020 Change in fair value of interest rate swaps $ 4.7 $ (17.1) Tax benefit (expense) (1.1) 4.0 Gain (loss) on designated cash flow hedge $ 3.6 $ (13.1) The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payment, included in our consolidated statements of operations were as follows (in millions): Three Months Ended 2021 2020 Interest expense $ 4.8 $ 1.3 We expect to recognize an additional $13.5 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): March 31, 2021 December 31, 2020 Fair value of derivative liabilities—current $ (5.7) $ (7.6) Commodity Swaps The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended 2021 2020 Change in fair value of derivatives $ (7.9) $ 13.0 Realized gain (loss) on derivatives (75.5) 6.2 Gain (loss) on derivative activity $ (83.4) $ 19.2 The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): March 31, 2021 December 31, 2020 Fair value of derivative assets—current $ 40.2 $ 25.0 Fair value of derivative assets—long-term 3.4 4.9 Fair value of derivative liabilities—current (53.6) (29.5) Fair value of derivative liabilities—long-term — (2.5) Net fair value of commodity swaps $ (10.0) $ (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 March 31, 2021 (in millions). The remaining term of the contracts extend no later than December 2022. March 31, 2021 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (204.2) $ (18.1) NGL (long contracts) Swaps Gallons 30.2 (0.1) Natural gas (short contracts) Swaps MMbtu (10.8) (0.3) Natural gas (long contracts) Swaps MMbtu 3.9 0.7 Crude and condensate (short contracts) Swaps MMbbls (9.5) (17.6) Crude and condensate (long contracts) Swaps MMbbls 4.3 25.4 Total fair value of commodity swaps $ (10.0)

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 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 March 31, 2021 December 31, 2020 Interest rate swaps (1) $ (5.7) $ (7.6) Commodity swaps (2) $ (10.0) $ (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): March 31, 2021 December 31, 2020 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,495.0 $ 4,207.7 $ 4,593.8 $ 4,318.2 ____________________________ (1) The carrying value of long-term debt includes current maturities and is reduced by debt issuance costs of $31.5 million and $32.6 million as of March 31, 2021 and December 31, 2020, respectively. The respective fair values do not factor in debt issuance costs. The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 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 March 31, 2021 Natural gas sales $ 125.0 $ 121.2 $ 35.9 $ 51.0 $ — $ 333.1 NGL sales — 626.0 0.6 1.2 — 627.8 Crude oil and condensate sales 107.3 41.1 13.6 — — 162.0 Product sales 232.3 788.3 50.1 52.2 — 1,122.9 NGL sales—related parties 164.9 23.6 113.1 80.9 (382.5) — Crude oil and condensate sales—related parties — — — 1.5 (1.5) — Product sales—related parties 164.9 23.6 113.1 82.4 (384.0) — Gathering and transportation 9.7 15.8 51.3 40.4 — 117.2 Processing 8.2 0.5 15.9 27.1 — 51.7 NGL services — 22.0 — 0.1 — 22.1 Crude services 3.5 9.9 3.3 0.2 — 16.9 Other services 0.2 0.5 0.2 0.1 — 1.0 Midstream services 21.6 48.7 70.7 67.9 — 208.9 Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 2.3 — — (2.3) — Midstream services—related parties — 2.3 0.1 — (2.4) — Revenue from contracts with customers 418.8 862.9 234.0 202.5 (386.4) 1,331.8 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (325.6) (740.4) (151.0) (104.1) 386.4 (934.7) Realized loss on derivatives (56.9) (10.7) (6.0) (1.9) — (75.5) Change in fair value of derivatives (5.3) (0.4) (1.8) (0.4) — (7.9) Adjusted gross margin 31.0 111.4 75.2 96.1 — 313.7 Operating expenses 11.8 (29.2) (19.7) (19.2) — (56.3) Segment profit 42.8 82.2 55.5 76.9 — 257.4 Depreciation and amortization (33.5) (36.1) (50.7) (28.7) (2.0) (151.0) Gain (loss) on disposition of assets 0.1 (0.1) — — — — General and administrative — — — — (26.0) (26.0) Interest expense, net of interest income — — — — (60.0) (60.0) Loss from unconsolidated affiliates — — — — (6.3) (6.3) Other expense — — — — (0.1) (0.1) Income (loss) before non-controlling interest and income taxes $ 9.4 $ 46.0 $ 4.8 $ 48.2 $ (94.4) $ 14.0 Capital expenditures $ 13.3 $ 2.8 $ 1.9 $ 2.4 $ 0.4 $ 20.8 ____________________________ (1) Includes related party cost of sales of $3.2 million for the three months ended March 31, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $149.0 million for the three months ended March 31, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended March 31, 2020 Natural gas sales $ 15.1 $ 81.6 $ 41.1 $ 20.1 $ — $ 157.9 NGL sales 0.2 373.7 1.2 0.3 — 375.4 Crude oil and condensate sales 285.0 58.4 16.2 — — 359.6 Product sales 300.3 513.7 58.5 20.4 — 892.9 NGL sales—related parties 45.9 6.8 67.6 17.2 (137.6) (0.1) Crude oil and condensate sales—related parties 0.1 — (0.2) 1.5 (1.3) 0.1 Product sales—related parties 46.0 6.8 67.4 18.7 (138.9) — Gathering and transportation 16.3 11.7 56.3 45.9 — 130.2 Processing 4.3 0.7 33.3 35.4 — 73.7 NGL services — 19.6 — — — 19.6 Crude services 4.2 10.6 4.3 — — 19.1 Other services 0.6 0.4 0.1 0.3 — 1.4 Midstream services 25.4 43.0 94.0 81.6 — 244.0 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 371.7 563.5 220.0 120.7 (139.0) 1,136.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (313.9) (459.7) (93.7) (27.0) 139.0 (755.3) Realized gain on derivatives 0.9 4.3 0.8 0.2 — 6.2 Change in fair value of derivatives 9.4 (1.0) 3.8 0.8 — 13.0 Adjusted gross margin 68.1 107.1 130.9 94.7 — 400.8 Operating expenses (25.5) (31.8) (22.9) (20.5) — (100.7) Segment profit 42.6 75.3 108.0 74.2 — 300.1 Depreciation and amortization (29.2) (37.8) (56.6) (37.2) (2.0) (162.8) Impairments (184.6) (168.4) — — — (353.0) Gain on disposition of assets 0.4 — 0.2 — — 0.6 General and administrative — — — — (30.4) (30.4) Interest expense, net of interest income — — — — (55.6) (55.6) Gain on extinguishment of debt — — — — 5.3 5.3 Income from unconsolidated affiliates — — — — 1.7 1.7 Income (loss) before non-controlling interest and income taxes $ (170.8) $ (130.9) $ 51.6 $ 37.0 $ (81.0) $ (294.1) Capital expenditures $ 86.0 $ 15.2 $ 8.5 $ 4.7 $ 0.4 $ 114.8 ____________________________ (1) Includes related party cost of sales of $2.9 million for the three months ended March 31, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $160.8 million for the three months ended March 31, 2020. The table below represents information about segment assets as of March 31, 2021 and December 31, 2020 (in millions): Segment Identifiable Assets: March 31, 2021 December 31, 2020 Permian $ 2,292.8 $ 2,236.3 Louisiana 2,316.7 2,312.4 Oklahoma 2,743.8 2,847.6 North Texas 986.0 1,008.6 Corporate (1) 177.0 146.0 Total identifiable assets $ 8,516.3 $ 8,550.9 ____________________________

Other Information

Other Information	3 Months Ended
	Mar. 31, 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: March 31, 2021 December 31, 2020 Natural gas and NGLs inventory $ 36.8 $ 44.9 Prepaid expenses and other 28.8 13.8 Other current assets $ 65.6 $ 58.7 Other current liabilities: March 31, 2021 December 31, 2020 Accrued interest $ 74.1 $ 35.7 Accrued wages and benefits, including taxes 8.8 22.5 Accrued ad valorem taxes 12.1 26.5 Capital expenditure accruals 8.7 10.6 Short-term lease liability 19.2 16.3 Operating expense accruals 17.8 8.4 Other 25.2 29.1 Other current liabilities $ 165.9 $ 149.1

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 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.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2021
Subsequent Events [Abstract]
Subsequent Events	(16) Subsequent Event Amarillo Rattler Acquisition. On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position and deepening our relationship 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 in 2022, and an earnout capped at $15 million based on Diamondback Energy’s drilling activity above historical levels.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 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 Recognition Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue. For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue.
Adopted Accounting Standards

Significant Accounting Polices

Significant Accounting Polices (Tables)	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table summarizes the contractually committed fees 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. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three months ended March 31, 2021, we had contractual commitments of $13.5 million under our MVC contracts and recorded $0.3 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2021 (remaining) $ 106.3 2022 127.5 2023 116.5 2024 104.4 2025 62.0 Thereafter 342.1 Total $ 858.8 ____________________________ (1) Amounts do not represent expected shortfall under these commitments.

Intangible Assets (Tables)

Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 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 Three Months Ended March 31, 2021 Customer relationships, beginning of period $ 1,794.2 $ (668.8) $ 1,125.4 Amortization expense — (30.9) (30.9) Customer relationships, end of period $ 1,794.2 $ (699.7) $ 1,094.5
Schedule of Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2021 (remaining) $ 92.5 2022 123.4 2023 123.4 2024 123.4 2025 106.1 Thereafter 525.7 Total $ 1,094.5

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
Summary of Debt	As of March 31, 2021 and December 31, 2020, long-term debt consisted of the following (in millions): March 31, 2021 December 31, 2020 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Term Loan due 2021 (1) $ 350.0 $ — $ 350.0 $ 350.0 $ — $ 350.0 AR Facility due 2023 (2) 150.0 — 150.0 250.0 — 250.0 Consolidated Credit Facility due 2024 — — — — — — ENLK’s 4.40% Senior unsecured notes due 2024 521.8 1.0 522.8 521.8 1.1 522.9 ENLK’s 4.15% Senior unsecured notes due 2025 720.8 (0.5) 720.3 720.8 (0.6) 720.2 ENLK’s 4.85% Senior unsecured notes due 2026 491.0 (0.4) 490.6 491.0 (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 $ 4,532.3 $ (5.8) 4,526.5 $ 4,632.3 $ (5.9) 4,626.4 Debt issuance cost (3) (31.5) (32.6) Less: Current maturities of long-term debt (1) (349.8) (349.8) Long-term debt, net of unamortized issuance cost $ 4,145.2 $ 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 March 31, 2021 and December 31, 2020, respectively. The Term Loan will mature on December 10, 2021. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of March 31, 2021 and December 31, 2020, respectively. (2) Bears interest based on LIMR and/or LIBOR plus an applicable margin. The effective interest rate was 1.4% and 2.0% at March 31, 2021 and December 31, 2020, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 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 2021 2020 Current income tax expense $ (0.1) $ (0.3) Deferred income tax benefit (expense) (1.3) 34.0 Income tax benefit (expense) $ (1.4) $ 33.7
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 2021 2020 Expected income tax benefit based on federal statutory rate $ 2.4 $ 67.3 State income tax benefit, net of federal benefit 0.2 8.0 Unit-based compensation (1) (2.5) 2.4 Non-deductible expense related to goodwill impairment — (43.4) Change in valuation allowance (1.2) — Other (0.3) (0.6) Income tax benefit (expense) $ (1.4) $ 33.7 ____________________________ (1) Related to book-to-tax differences recorded upon the vesting of restricted incentive units.

Certain Provisions of the ENL_2

Certain Provisions of the ENLK Partnership Agreement (Tables)	3 Months Ended
	Mar. 31, 2021
Partners' Capital [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 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 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020

Members' Equity (Tables)

Members' Equity (Tables)	3 Months Ended
	Mar. 31, 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 2021 2020 Distributed earnings allocated to: Common units (1) $ 45.9 $ 45.8 Unvested restricted units (1) 1.1 0.8 Total distributed earnings $ 47.0 $ 46.6 Undistributed loss allocated to: Common units $ (58.3) $ (327.4) Unvested restricted units (1.4) (6.0) Total undistributed loss $ (59.7) $ (333.4) Net loss allocated to: Common units $ (12.4) $ (281.6) Unvested restricted units (0.3) (5.2) Total net loss $ (12.7) $ (286.8) Basic and diluted total net loss per unit: Basic $ (0.03) $ (0.59) Diluted $ (0.03) $ (0.59) ____________________________ (1) Represents distribution activity consistent with the distribution activity in “ Distributions ” below.
Summary of Distribution Activity	A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 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 2020 Fourth Quarter of 2019 $ 0.1875 February 13, 2020 First Quarter of 2020 $ 0.09375 May 13, 2020

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 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 2021 2020 GCF Distributions $ 3.5 $ 1.6 Equity in income (loss) $ (5.7) $ 1.8 Cedar Cove JV Distributions $ 0.1 $ 0.2 Equity in loss $ (0.6) $ (0.1) Total Distributions $ 3.6 $ 1.8 Equity in income (loss) $ (6.3) $ 1.7 The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2021 and December 31, 2020 (in millions): March 31, 2021 December 31, 2020 GCF $ 31.4 $ 40.6 Cedar Cove JV 0.3 1.0 Total investment in unconsolidated affiliates $ 31.7 $ 41.6

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	3 Months Ended
	Mar. 31, 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 2021 2020 Cost of unit-based compensation charged to operating expense $ 1.7 $ 2.2 Cost of unit-based compensation charged to general and administrative expense 4.8 6.6 Total unit-based compensation expense $ 6.5 $ 8.8 Amount of related income tax benefit recognized in net income (loss) (1) $ 1.5 $ 2.1 ____________________________
Schedule Of Restricted Stock Units Activity, ENLC	A summary of the restricted incentive unit activity for the three months ended March 31, 2021 is provided below: Three 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) 3,622,698 3.72 Vested (1)(2) (813,686) 12.52 Forfeited (116,444) 6.62 Non-vested, end of period 8,042,654 $ 5.93 Aggregate intrinsic value, end of period (in millions) $ 34.5 ____________________________ (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 months ended March 31, 2021 and 2020 is provided below (in millions): Three Months Ended ENLC Restricted Incentive Units: 2021 2020 Aggregate intrinsic value of units vested $ 3.0 $ 10.1 Fair value of units vested $ 10.2 $ 18.9
Summary of Performance Units, ENLC	The following table presents a summary of the performance units: Three 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) $ 15.3 ____________________________ (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 three months ended March 31, 2021 and 2020 is provided below (in millions). Three Months Ended ENLC Performance Units: 2021 2020 Aggregate intrinsic value of units vested $ 0.6 $ 0.9 Fair value of units vested $ 4.4 $ 5.0
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)	3 Months Ended
	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Components of Gain (Loss) on Derivative Activity	The components of the 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 2021 2020 Change in fair value of interest rate swaps $ 4.7 $ (17.1) Tax benefit (expense) (1.1) 4.0 Gain (loss) on designated cash flow hedge $ 3.6 $ (13.1) The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payment, included in our consolidated statements of operations were as follows (in millions): Three Months Ended 2021 2020 Interest expense $ 4.8 $ 1.3 The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended 2021 2020 Change in fair value of derivatives $ (7.9) $ 13.0 Realized gain (loss) on derivatives (75.5) 6.2 Gain (loss) on derivative activity $ (83.4) $ 19.2
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): March 31, 2021 December 31, 2020 Fair value of derivative liabilities—current $ (5.7) $ (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): March 31, 2021 December 31, 2020 Fair value of derivative assets—current $ 40.2 $ 25.0 Fair value of derivative assets—long-term 3.4 4.9 Fair value of derivative liabilities—current (53.6) (29.5) Fair value of derivative liabilities—long-term — (2.5) Net fair value of commodity swaps $ (10.0) $ (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 March 31, 2021 (in millions). The remaining term of the contracts extend no later than December 2022. March 31, 2021 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (204.2) $ (18.1) NGL (long contracts) Swaps Gallons 30.2 (0.1) Natural gas (short contracts) Swaps MMbtu (10.8) (0.3) Natural gas (long contracts) Swaps MMbtu 3.9 0.7 Crude and condensate (short contracts) Swaps MMbbls (9.5) (17.6) Crude and condensate (long contracts) Swaps MMbbls 4.3 25.4 Total fair value of commodity swaps $ (10.0)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2021 December 31, 2020 Interest rate swaps (1) $ (5.7) $ (7.6) Commodity swaps (2) $ (10.0) $ (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): March 31, 2021 December 31, 2020 Carrying Value Fair Carrying Value Fair Long-term debt (1) $ 4,495.0 $ 4,207.7 $ 4,593.8 $ 4,318.2 ____________________________

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2021 Natural gas sales $ 125.0 $ 121.2 $ 35.9 $ 51.0 $ — $ 333.1 NGL sales — 626.0 0.6 1.2 — 627.8 Crude oil and condensate sales 107.3 41.1 13.6 — — 162.0 Product sales 232.3 788.3 50.1 52.2 — 1,122.9 NGL sales—related parties 164.9 23.6 113.1 80.9 (382.5) — Crude oil and condensate sales—related parties — — — 1.5 (1.5) — Product sales—related parties 164.9 23.6 113.1 82.4 (384.0) — Gathering and transportation 9.7 15.8 51.3 40.4 — 117.2 Processing 8.2 0.5 15.9 27.1 — 51.7 NGL services — 22.0 — 0.1 — 22.1 Crude services 3.5 9.9 3.3 0.2 — 16.9 Other services 0.2 0.5 0.2 0.1 — 1.0 Midstream services 21.6 48.7 70.7 67.9 — 208.9 Crude services—related parties — — 0.1 — (0.1) — Other services—related parties — 2.3 — — (2.3) — Midstream services—related parties — 2.3 0.1 — (2.4) — Revenue from contracts with customers 418.8 862.9 234.0 202.5 (386.4) 1,331.8 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (325.6) (740.4) (151.0) (104.1) 386.4 (934.7) Realized loss on derivatives (56.9) (10.7) (6.0) (1.9) — (75.5) Change in fair value of derivatives (5.3) (0.4) (1.8) (0.4) — (7.9) Adjusted gross margin 31.0 111.4 75.2 96.1 — 313.7 Operating expenses 11.8 (29.2) (19.7) (19.2) — (56.3) Segment profit 42.8 82.2 55.5 76.9 — 257.4 Depreciation and amortization (33.5) (36.1) (50.7) (28.7) (2.0) (151.0) Gain (loss) on disposition of assets 0.1 (0.1) — — — — General and administrative — — — — (26.0) (26.0) Interest expense, net of interest income — — — — (60.0) (60.0) Loss from unconsolidated affiliates — — — — (6.3) (6.3) Other expense — — — — (0.1) (0.1) Income (loss) before non-controlling interest and income taxes $ 9.4 $ 46.0 $ 4.8 $ 48.2 $ (94.4) $ 14.0 Capital expenditures $ 13.3 $ 2.8 $ 1.9 $ 2.4 $ 0.4 $ 20.8 ____________________________ (1) Includes related party cost of sales of $3.2 million for the three months ended March 31, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $149.0 million for the three months ended March 31, 2021. Permian Louisiana Oklahoma North Texas Corporate Totals Three Months Ended March 31, 2020 Natural gas sales $ 15.1 $ 81.6 $ 41.1 $ 20.1 $ — $ 157.9 NGL sales 0.2 373.7 1.2 0.3 — 375.4 Crude oil and condensate sales 285.0 58.4 16.2 — — 359.6 Product sales 300.3 513.7 58.5 20.4 — 892.9 NGL sales—related parties 45.9 6.8 67.6 17.2 (137.6) (0.1) Crude oil and condensate sales—related parties 0.1 — (0.2) 1.5 (1.3) 0.1 Product sales—related parties 46.0 6.8 67.4 18.7 (138.9) — Gathering and transportation 16.3 11.7 56.3 45.9 — 130.2 Processing 4.3 0.7 33.3 35.4 — 73.7 NGL services — 19.6 — — — 19.6 Crude services 4.2 10.6 4.3 — — 19.1 Other services 0.6 0.4 0.1 0.3 — 1.4 Midstream services 25.4 43.0 94.0 81.6 — 244.0 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 371.7 563.5 220.0 120.7 (139.0) 1,136.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (313.9) (459.7) (93.7) (27.0) 139.0 (755.3) Realized gain on derivatives 0.9 4.3 0.8 0.2 — 6.2 Change in fair value of derivatives 9.4 (1.0) 3.8 0.8 — 13.0 Adjusted gross margin 68.1 107.1 130.9 94.7 — 400.8 Operating expenses (25.5) (31.8) (22.9) (20.5) — (100.7) Segment profit 42.6 75.3 108.0 74.2 — 300.1 Depreciation and amortization (29.2) (37.8) (56.6) (37.2) (2.0) (162.8) Impairments (184.6) (168.4) — — — (353.0) Gain on disposition of assets 0.4 — 0.2 — — 0.6 General and administrative — — — — (30.4) (30.4) Interest expense, net of interest income — — — — (55.6) (55.6) Gain on extinguishment of debt — — — — 5.3 5.3 Income from unconsolidated affiliates — — — — 1.7 1.7 Income (loss) before non-controlling interest and income taxes $ (170.8) $ (130.9) $ 51.6 $ 37.0 $ (81.0) $ (294.1) Capital expenditures $ 86.0 $ 15.2 $ 8.5 $ 4.7 $ 0.4 $ 114.8 ____________________________
Schedule of Segment Assets	The table below represents information about segment assets as of March 31, 2021 and December 31, 2020 (in millions): Segment Identifiable Assets: March 31, 2021 December 31, 2020 Permian $ 2,292.8 $ 2,236.3 Louisiana 2,316.7 2,312.4 Oklahoma 2,743.8 2,847.6 North Texas 986.0 1,008.6 Corporate (1) 177.0 146.0 Total identifiable assets $ 8,516.3 $ 8,550.9 ____________________________

Other Information (Tables)

Other Information (Tables)	3 Months Ended
	Mar. 31, 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: March 31, 2021 December 31, 2020 Natural gas and NGLs inventory $ 36.8 $ 44.9 Prepaid expenses and other 28.8 13.8 Other current assets $ 65.6 $ 58.7 Other current liabilities: March 31, 2021 December 31, 2020 Accrued interest $ 74.1 $ 35.7 Accrued wages and benefits, including taxes 8.8 22.5 Accrued ad valorem taxes 12.1 26.5 Capital expenditure accruals 8.7 10.6 Short-term lease liability 19.2 16.3 Operating expense accruals 17.8 8.4 Other 25.2 29.1 Other current liabilities $ 165.9 $ 149.1

General (Details)

General (Details) bbl in Thousands	3 Months Ended
	Mar. 31, 2021Bcf / dplantfractionatormibbl
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of miles of pipeline | mi	11,900
Number of natural gas processing plants | plant	22
Amount of processing capacity | Bcf / d	5,500,000,000
Number of fractionators | fractionator	7
Capacity of fractionators per day, barrels | bbl	290

Significant Accounting Polici_3

Significant Accounting Policies - Narrative (Details) - Minimum Volume Contract $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract with customer, liability	$ 13.5
Contracts with customers, revenue recognition	$ 0.3

Significant Accounting Polici_4

Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	Mar. 31, 2021USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 858.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 106.3
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	$ 127.5
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]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 116.5
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	$ 104.4
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	$ 62
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	$ 342.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations expected to be recognized, period

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Amortization expense		$ 30.9
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	15 years

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning Balance	$ (668.8)
Amortization expense		$ (30.9)
Accumulated Amortization, Ending Balance	(699.7)
Net Carrying Amount, Ending Balance	1,094.5
Customer relationships
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
Amortization expense	(30.9)
Gross Carrying Amount, Ending Balance	1,794.2
Accumulated Amortization, Ending Balance	(699.7)
Net Carrying Amount, Ending Balance	$ 1,094.5

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) $ in Millions	Mar. 31, 2021USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2021 (remaining)	$ 92.5
2022	123.4
2023	123.4
2024	123.4
2025	106.1
Thereafter	525.7
Total	$ 1,094.5

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization	$ 934,700,000	$ 755,300,000
Accounts payable to related party	1,200,000		$ 1,000,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales, exclusive of operating expenses and depreciation and amortization	3,200,000	2,900,000
Accounts payable to related party	1,200,000		$ 1,000,000
GIP
Related Party Transaction [Line Items]
General and administrative expenses from transactions with related party	$ 100,000	$ 0

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Debt Instrument
Outstanding principal	$ 4,532.3	$ 4,632.3
Premium (discount)	(5.8)	(5.9)
Long-term debt	4,526.5	4,626.4
Debt issuance costs	(31.5)	(32.6)
Less: Current maturities of long-term debt	(349.8)	(349.8)
Long-term debt, net of unamortized issuance cost	4,145.2	4,244
Debt issuance cost accumulated amortization	15.3	14.1
Term Loan Due 2021
Debt Instrument
Outstanding principal	350	350
Premium (discount)	0	0
Long-term debt	$ 350	$ 350
Effective interest rate	1.60%	1.70%
AR Facility due 2023
Debt Instrument
Outstanding principal	$ 150	$ 250
Premium (discount)	0	0
Long-term debt	$ 150	$ 250
Effective interest rate	1.40%	2.00%
Consolidated Credit Facility due 2024
Debt Instrument
Outstanding principal	$ 0	$ 0
Premium (discount)	0	0
Long-term debt	0	0
4.4% Senior Notes Due 2024
Debt Instrument
Outstanding principal	521.8	521.8
Premium (discount)	1	1.1
Long-term debt	$ 522.8	522.9
Stated interest rate	4.40%
4.15% Senior Notes Due 2025
Debt Instrument
Outstanding principal	$ 720.8	720.8
Premium (discount)	(0.5)	(0.6)
Long-term debt	$ 720.3	720.2
Stated interest rate	4.15%
4.85 Senior Notes Due 2026
Debt Instrument
Outstanding principal	$ 491	491
Premium (discount)	(0.4)	(0.4)
Long-term debt	$ 490.6	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) - USD ($)	Feb. 26, 2021	Oct. 21, 2020	Mar. 31, 2021	Dec. 31, 2020
Debt Instrument
Increase (decrease) in accounts receivable			$ 505,900,000
Outstanding principal			4,532,300,000	$ 4,632,300,000
AR Facility due 2023
Debt Instrument
Outstanding principal			150,000,000	250,000,000
Letters of credit
Debt Instrument
Line of credit facility, fair value of amount outstanding			0
Additional amount available (not to exceed)			1,750,000,000
Term Loan Due 2021
Debt Instrument
Outstanding principal			350,000,000	$ 350,000,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity	$ 300,000,000	$ 250,000,000	262,100,000
Line of credit facility, increase in period	$ 50,000,000
Drawn fee percentage	1.25%	1.625%
Letter of Credit | Letters of credit | ENLC
Debt Instrument
Line of credit facility, fair value of amount outstanding			27,500,000
LIBOR | Line of Credit | Minimum | Asset-backed Securities
Debt Instrument
Variable rate	0.00%	0.375%
Letter of Credit | Letters of credit
Debt Instrument
Maximum borrowing capacity			500,000,000
Unsecured Debt | Term Loan Due 2021
Debt Instrument
Face amount			$ 350,000,000

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Provision) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.1)	$ (0.3)
Deferred income tax benefit (expense)	(1.3)	34
Income tax benefit (expense)	(1.4)	33.7
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax benefit based on federal statutory rate	2.4	67.3
State income tax benefit, net of federal benefit	0.2	8
Unit-based compensation	(2.5)	2.4
Non-deductible expense related to goodwill impairment	0	(43.4)
Change in valuation allowance	(1.2)	0
Other	(0.3)	(0.6)
Income tax benefit (expense)	$ (1.4)	$ 33.7

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ 111		$ 108.6
Deferred tax assets	404.5		396
Deferred tax assets, valuation allowance	(154.5)		$ (153.3)
Change in valuation allowance	$ (1.2)	$ 0

Certain Provisions of the ENL_3

Certain Provisions of the ENLK Partnership Agreement - Narrative and Distributions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2019
Series B Preferred Unitholders
Partnership agreement
Distribution paid-in kind (in shares)	150,871	150,494	149,371	148,999
Cash distributions	$ 17	$ 16.9	$ 16.8	$ 16.8
Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)	60,348,278	60,197,784
Preferred units, outstanding (in shares)	60,348,278	60,197,784
Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Preferred units, issued (in shares)	400,000	400,000
Preferred units, outstanding (in shares)	400,000	400,000

Members' Equity - Computation a

Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2019
Distributed earnings allocated to:
Total distributed earnings	$ 47		$ 46.6
Undistributed loss allocated to:
Total undistributed loss	(59.7)		(333.4)
Net loss allocated to:
Total net loss	$ (12.7)		$ (286.8)
Basic and diluted total net loss per unit:
Basic (in dollars per share)	$ (0.03)		$ (0.59)
Diluted (in dollars per share)	(0.03)		(0.59)
Distribution declared/unit (in dollars per share)	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.1875
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings	$ 1.1		$ 0.8
Undistributed loss allocated to:
Total undistributed loss	(1.4)		(6)
Net loss allocated to:
Total net loss	(0.3)		(5.2)
Common units
Distributed earnings allocated to:
Total distributed earnings	45.9		45.8
Undistributed loss allocated to:
Total undistributed loss	(58.3)		(327.4)
Net loss allocated to:
Total net loss	$ (12.4)		$ (281.6)

Members' Equity - Components to

Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Earnings Per Share [Abstract]
Weighted average basic and diluted common units outstanding (in units)	490	488.7

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Equity method investments
Distributions	$ 3.6	$ 1.8
Loss from unconsolidated affiliates	(6.3)	1.7
Total investment in unconsolidated affiliates	$ 31.7		$ 41.6
GCF
Equity method investments
Ownership interest	38.75%
Distributions	$ 3.5	1.6
Loss from unconsolidated affiliates	$ (5.7)	1.8
Cedar Cove JV
Equity method investments
Ownership interest	30.00%
Distributions	$ 0.1	0.2
Loss from unconsolidated affiliates	(0.6)	$ (0.1)
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	31.7		41.6
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	31.4		40.6
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	$ 0.3		$ 1

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Allocation
Compensation expense	$ 6.5	$ 8.8
Amount of related income tax benefit recognized in net income (loss)	1.5	2.1
Restricted units
Allocation
Amount of related income tax benefit recognized in net income (loss)	(2.5)	2.4
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	1.7	2.2
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	$ 4.8	$ 6.6

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended				3 Months Ended
	Jan. 31, 2021	Jul. 31, 2020	Mar. 31, 2020	Jan. 31, 2020	Mar. 31, 2021	Mar. 31, 2020
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%
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)					3,622,698
Vested (in shares)					(813,686)
Forfeited (in shares)					(116,444)
Non-vested, end of period (in shares)					8,042,654
Aggregate intrinsic value, end of period					$ 34.5
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)					3.72
Vested (in dollars per share)					12.52
Forfeited (in dollars per share)					6.62
Non-vested, end of period (in dollars per share)					$ 5.93
Incentive unit award vesting period					3 years
Units withheld for payroll taxes (in shares)					240,085
Unrecognized compensation cost related to non-vested restricted incentive units					$ 26.6
Unrecognized compensation costs, weighted average period for recognition					1 year 10 months 24 days
Unvested restricted units | ENLC
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Fair value of units vested					$ 10.2	$ 18.9
Aggregate intrinsic value of units vested					$ 3	10.1
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
Aggregate intrinsic value, end of period					$ 15.3
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
Fair value of units vested					$ 4.4	5
Units withheld for payroll taxes (in shares)					63,901
Aggregate intrinsic value of units vested					$ 0.6	$ 0.9
Unrecognized compensation cost related to non-vested restricted incentive units					$ 14.9
Unrecognized compensation costs, weighted average period for recognition					1 year 9 months 18 days
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
		Dec. 31, 2020	Mar. 31, 2021		Mar. 31, 2020	Apr. 30, 2019
Derivatives
Derivative, notional amount			$ 350,000,000			$ 850,000,000
Derivative, fixed interest rate						2.28%
Derivative, termination payment		$ 10,900,000
Derivative, notional amount, amount terminated		500,000,000
Derivative liability		10,900,000
Change in fair value of derivatives due to accelerated amortization			2,900,000
(Loss) gain on interest rate swaps			4,800,000		$ 1,300,000
Change in fair value of derivatives			(7,900,000)		13,000,000
Tax benefit (expense)			(1,100,000)	[1]	4,000,000
(Loss) gain on designated cash flow hedge	[1],[2]		3,600,000		(13,100,000)
Interest expense expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months			13,500,000
Fair value of derivative liabilities—current		(37,100,000)	(59,300,000)
Interest rate swaps
Derivatives
Change in fair value of derivatives			4,700,000		$ (17,100,000)
Fair value of derivative liabilities—current		$ (7,600,000)	$ (5,700,000)
[1]	Includes a tax expense of $1.1 million and a tax benefit of $4.0 million for the three months ended March 31, 2021 and 2020, respectively.
[2]	Includes a tax expense of $1.1 million.

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Derivatives
Change in fair value of derivatives	$ (7.9)	$ 13
Realized gain (loss) on derivatives	(7.8)	18
Gain (loss) on derivative activity	(83.4)	19.2
Commodity swaps
Derivatives
Realized gain (loss) on derivatives	(75.5)	6.2
EnLink Midstream Partners, LP | Commodity swaps
Derivatives
Change in fair value of derivatives	(7.9)	13
Realized gain (loss) on derivatives	(75.5)	6.2
Gain (loss) on derivative activity	$ (83.4)	$ 19.2

Derivatives - Fair Value of Ass

Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Derivatives
Fair value of derivative assets—current	$ 40.2	$ 25
Fair value of derivative assets—long-term	3.4	4.9
Fair value of derivative liabilities—current	(59.3)	(37.1)
Fair value of derivative liabilities—long-term	0	(2.5)
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	40.2	25
Fair value of derivative assets—long-term	3.4	4.9
Fair value of derivative liabilities—current	(53.6)	(29.5)
Fair value of derivative liabilities—long-term	0	(2.5)
Net fair value of commodity swaps	$ (10)	$ (2.1)

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)MMBTUgalMMBbls	Dec. 31, 2020USD ($)
Derivatives
Net Fair Value	$ (10)	$ (2.1)
Commodity
Derivatives
Net Fair Value	(10)
Maximum loss if counterparties fail to perform	43.6
Possible reduction in maximum loss if counterparties fail to perform	$ 7.5
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	204.2
Net Fair Value	$ (18.1)
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	30.2
Net Fair Value	$ (0.1)
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	10.8
Net Fair Value	$ (0.3)
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	3.9
Net Fair Value	$ 0.7
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	9.5
Net Fair Value	$ (17.6)
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	4.3
Net Fair Value	$ 25.4

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Details) - Level 2 - Recurring - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Interest rate swaps
Fair Value
Net Fair Value	$ (5.7)	$ (7.6)
Commodity swaps
Fair Value
Net Fair Value	$ (10)	$ (2.1)

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Fair Value
Debt issuance costs	$ 31.5	$ 32.6
Carrying Value
Fair Value
Long-term debt	4,495	4,593.8
Fair Value
Fair Value
Long-term debt	$ 4,207.7	$ 4,318.2

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Segment Reporting
Revenue from contracts with customers	$ 1,331.8	$ 1,136.9
Cost of sales, exclusive of operating expenses and depreciation and amortization	(934.7)	(755.3)
Realized gain (loss) on derivatives	(7.8)	18
Change in fair value of derivatives	(7.9)	13
Adjusted gross margin	313.7	400.8
Operating expenses	(56.3)	(100.7)
Segment profit	257.4	300.1
Depreciation and amortization	(151)	(162.8)
Impairments	0	(353)
Gain (loss) on disposition of assets	0	0.6
General and administrative	(26)	(30.4)
Interest expense, net of interest income	(60)	(55.6)
Gain on extinguishment of debt	0	5.3
Loss from unconsolidated affiliates	(6.3)	1.7
Other expense	(0.1)	0
Income (loss) before non-controlling interest and income taxes	14	(294.1)
Capital expenditures	20.8	114.8
Related parties amount in cost of sales	3.2	2.9
Other depreciation and amortization	149	160.8
Commodity swaps
Segment Reporting
Realized gain (loss) on derivatives	(75.5)	6.2
Permian
Segment Reporting
Revenue from contracts with customers	418.8	371.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	(325.6)	(313.9)
Change in fair value of derivatives	(5.3)	9.4
Adjusted gross margin	31	68.1
Operating expenses	11.8	(25.5)
Segment profit	42.8	42.6
Depreciation and amortization	(33.5)	(29.2)
Impairments		(184.6)
Gain (loss) on disposition of assets	0.1	0.4
General and administrative	0	0
Interest expense, net of interest income	0	0
Gain on extinguishment of debt		0
Loss from unconsolidated affiliates	0	0
Other expense	0
Income (loss) before non-controlling interest and income taxes	9.4	(170.8)
Capital expenditures	13.3	86
Permian | Commodity swaps
Segment Reporting
Realized gain (loss) on derivatives	(56.9)	0.9
Louisiana
Segment Reporting
Revenue from contracts with customers	862.9	563.5
Cost of sales, exclusive of operating expenses and depreciation and amortization	(740.4)	(459.7)
Change in fair value of derivatives	(0.4)	(1)
Adjusted gross margin	111.4	107.1
Operating expenses	(29.2)	(31.8)
Segment profit	82.2	75.3
Depreciation and amortization	(36.1)	(37.8)
Impairments		(168.4)
Gain (loss) on disposition of assets	(0.1)	0
General and administrative	0	0
Interest expense, net of interest income	0	0
Gain on extinguishment of debt		0
Loss from unconsolidated affiliates	0	0
Other expense	0
Income (loss) before non-controlling interest and income taxes	46	(130.9)
Capital expenditures	2.8	15.2
Louisiana | Commodity swaps
Segment Reporting
Realized gain (loss) on derivatives	(10.7)	4.3
Oklahoma
Segment Reporting
Revenue from contracts with customers	234	220
Cost of sales, exclusive of operating expenses and depreciation and amortization	(151)	(93.7)
Change in fair value of derivatives	(1.8)	3.8
Adjusted gross margin	75.2	130.9
Operating expenses	(19.7)	(22.9)
Segment profit	55.5	108
Depreciation and amortization	(50.7)	(56.6)
Impairments		0
Gain (loss) on disposition of assets	0	0.2
General and administrative	0	0
Interest expense, net of interest income	0	0
Gain on extinguishment of debt		0
Loss from unconsolidated affiliates	0	0
Other expense	0
Income (loss) before non-controlling interest and income taxes	4.8	51.6
Capital expenditures	1.9	8.5
Oklahoma | Commodity swaps
Segment Reporting
Realized gain (loss) on derivatives	(6)	0.8
North Texas
Segment Reporting
Revenue from contracts with customers	202.5	120.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	(104.1)	(27)
Change in fair value of derivatives	(0.4)	0.8
Adjusted gross margin	96.1	94.7
Operating expenses	(19.2)	(20.5)
Segment profit	76.9	74.2
Depreciation and amortization	(28.7)	(37.2)
Impairments		0
Gain (loss) on disposition of assets	0	0
General and administrative	0	0
Interest expense, net of interest income	0	0
Gain on extinguishment of debt		0
Loss from unconsolidated affiliates	0	0
Other expense	0
Income (loss) before non-controlling interest and income taxes	48.2	37
Capital expenditures	2.4	4.7
North Texas | Commodity swaps
Segment Reporting
Realized gain (loss) on derivatives	(1.9)	0.2
Corporate
Segment Reporting
Revenue from contracts with customers	(386.4)	(139)
Cost of sales, exclusive of operating expenses and depreciation and amortization	386.4	139
Change in fair value of derivatives	0	0
Adjusted gross margin	0	0
Operating expenses	0	0
Segment profit	0	0
Depreciation and amortization	(2)	(2)
Impairments		0
Gain (loss) on disposition of assets	0	0
General and administrative	(26)	(30.4)
Interest expense, net of interest income	(60)	(55.6)
Gain on extinguishment of debt		5.3
Loss from unconsolidated affiliates	(6.3)	1.7
Other expense	(0.1)
Income (loss) before non-controlling interest and income taxes	(94.4)	(81)
Capital expenditures	0.4	0.4
Corporate | Commodity swaps
Segment Reporting
Realized gain (loss) on derivatives	0	0
Product sales
Segment Reporting
Revenue from contracts with customers	1,122.9	892.9
Product sales | Permian
Segment Reporting
Revenue from contracts with customers	232.3	300.3
Product sales | Louisiana
Segment Reporting
Revenue from contracts with customers	788.3	513.7
Product sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	50.1	58.5
Product sales | North Texas
Segment Reporting
Revenue from contracts with customers	52.2	20.4
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers	333.1	157.9
Product sales, Natural gas sales | Permian
Segment Reporting
Revenue from contracts with customers	125	15.1
Product sales, Natural gas sales | Louisiana
Segment Reporting
Revenue from contracts with customers	121.2	81.6
Product sales, Natural gas sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	35.9	41.1
Product sales, Natural gas sales | North Texas
Segment Reporting
Revenue from contracts with customers	51	20.1
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers	627.8	375.4
Product sales, NGL sales | Permian
Segment Reporting
Revenue from contracts with customers	0	0.2
Product sales, NGL sales | Louisiana
Segment Reporting
Revenue from contracts with customers	626	373.7
Product sales, NGL sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.6	1.2
Product sales, NGL sales | North Texas
Segment Reporting
Revenue from contracts with customers	1.2	0.3
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers	162	359.6
Product sales, Crude oil and condensate sales | Permian
Segment Reporting
Revenue from contracts with customers	107.3	285
Product sales, Crude oil and condensate sales | Louisiana
Segment Reporting
Revenue from contracts with customers	41.1	58.4
Product sales, Crude oil and condensate sales | Oklahoma
Segment Reporting
Revenue from contracts with customers	13.6	16.2
Product sales, Crude oil and condensate sales | North Texas
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Product sales—related parties | Permian
Segment Reporting
Revenue from contracts with customers	164.9	46
Product sales—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	23.6	6.8
Product sales—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	113.1	67.4
Product sales—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	82.4	18.7
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(384)	(138.9)
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers	0	(0.1)
Product sales, NGL sales, related party | Permian
Segment Reporting
Revenue from contracts with customers	164.9	45.9
Product sales, NGL sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	23.6	6.8
Product sales, NGL sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	113.1	67.6
Product sales, NGL sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers	80.9	17.2
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(382.5)	(137.6)
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers	0	0.1
Product sales, Crude oil and condensate sales, related party | Permian
Segment Reporting
Revenue from contracts with customers	0	0.1
Product sales, Crude oil and condensate sales, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Crude oil and condensate sales, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	(0.2)
Product sales, Crude oil and condensate sales, related party | North Texas
Segment Reporting
Revenue from contracts with customers	1.5	1.5
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(1.5)	(1.3)
Midstream services
Segment Reporting
Revenue from contracts with customers	208.9	244
Midstream services | Permian
Segment Reporting
Revenue from contracts with customers	21.6	25.4
Midstream services | Louisiana
Segment Reporting
Revenue from contracts with customers	48.7	43
Midstream services | Oklahoma
Segment Reporting
Revenue from contracts with customers	70.7	94
Midstream services | North Texas
Segment Reporting
Revenue from contracts with customers	67.9	81.6
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers	117.2	130.2
Midstream services, Gathering and transportation | Permian
Segment Reporting
Revenue from contracts with customers	9.7	16.3
Midstream services, Gathering and transportation | Louisiana
Segment Reporting
Revenue from contracts with customers	15.8	11.7
Midstream services, Gathering and transportation | Oklahoma
Segment Reporting
Revenue from contracts with customers	51.3	56.3
Midstream services, Gathering and transportation | North Texas
Segment Reporting
Revenue from contracts with customers	40.4	45.9
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers	51.7	73.7
Midstream services, Processing | Permian
Segment Reporting
Revenue from contracts with customers	8.2	4.3
Midstream services, Processing | Louisiana
Segment Reporting
Revenue from contracts with customers	0.5	0.7
Midstream services, Processing | Oklahoma
Segment Reporting
Revenue from contracts with customers	15.9	33.3
Midstream services, Processing | North Texas
Segment Reporting
Revenue from contracts with customers	27.1	35.4
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers	22.1	19.6
Midstream services, NGL services | Permian
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services | Louisiana
Segment Reporting
Revenue from contracts with customers	22	19.6
Midstream services, NGL services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services | North Texas
Segment Reporting
Revenue from contracts with customers	0.1	0
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers	16.9	19.1
Midstream services, Crude services | Permian
Segment Reporting
Revenue from contracts with customers	3.5	4.2
Midstream services, Crude services | Louisiana
Segment Reporting
Revenue from contracts with customers	9.9	10.6
Midstream services, Crude services | Oklahoma
Segment Reporting
Revenue from contracts with customers	3.3	4.3
Midstream services, Crude services | North Texas
Segment Reporting
Revenue from contracts with customers	0.2	0
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers	1	1.4
Midstream services, Other services | Permian
Segment Reporting
Revenue from contracts with customers	0.2	0.6
Midstream services, Other services | Louisiana
Segment Reporting
Revenue from contracts with customers	0.5	0.4
Midstream services, Other services | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.2	0.1
Midstream services, Other services | North Texas
Segment Reporting
Revenue from contracts with customers	0.1	0.3
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Permian
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Louisiana
Segment Reporting
Revenue from contracts with customers	2.3	0
Midstream services—related parties | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.1
Midstream services—related parties | North Texas
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(2.4)	(0.1)
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | Permian
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0.1	0.1
Midstream services, Crude services, related party | North Texas
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(0.1)	$ (0.1)
Midstream services, Other services, related party
Segment Reporting
Revenue from contracts with customers	0
Midstream services, Other services, related party | Permian
Segment Reporting
Revenue from contracts with customers	0
Midstream services, Other services, related party | Louisiana
Segment Reporting
Revenue from contracts with customers	2.3
Midstream services, Other services, related party | Oklahoma
Segment Reporting
Revenue from contracts with customers	0
Midstream services, Other services, related party | North Texas
Segment Reporting
Revenue from contracts with customers	0
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers	$ (2.3)

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Segment Reporting
Total identifiable assets	$ 8,516.3	$ 8,550.9
Permian
Segment Reporting
Total identifiable assets	2,292.8	2,236.3
Louisiana
Segment Reporting
Total identifiable assets	2,316.7	2,312.4
Oklahoma
Segment Reporting
Total identifiable assets	2,743.8	2,847.6
North Texas
Segment Reporting
Total identifiable assets	986	1,008.6
Corporate
Segment Reporting
Total identifiable assets	$ 177	$ 146

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Other current assets:
Natural gas and NGLs inventory	$ 36.8	$ 44.9
Prepaid expenses and other	28.8	13.8
Other current assets	65.6	58.7
Other current liabilities:
Accrued interest	74.1	35.7
Accrued wages and benefits, including taxes	8.8	22.5
Accrued ad valorem taxes	12.1	26.5
Capital expenditure accruals	8.7	10.6
Short-term lease liability	19.2	16.3
Operating expense accruals	17.8	8.4
Other	25.2	29.1
Other current liabilities	$ 165.9	$ 149.1

Subsequent Event (Details)

Subsequent Event (Details) - Subsequent Event - Amarillo Rattler, LLC $ in Millions	Apr. 30, 2021USD ($)
Subsequent Event [Line Items]
Payments to acquire gathering and processing system	$ 50
Amount payable for gathering and processing system	10
Business combination, earnout	$ 15